SEC Filing | Sempra

View:

Download DOC

Download PDF

Download XLS

Download XBRL

Unassociated Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

]

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

For the fiscal year ended

December 31, 2015

[

]

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

For the transition period from

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

488 8th Avenue

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

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, 2015:

Sempra Energy	$24.5 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 19, 2016:

Sempra Energy	249,215,763 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

SAN DIEGO GAS & ELECTRIC COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY GENERAL INSTRUCTION I(2). DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the 2015 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 its May 2016 annual meeting of shareholders are incorporated by reference into Part III.

Portions of the Southern California Gas Company Information Statement prepared for its May 2016 annual meeting 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
	Description of Business	8
	Company Websites	8
	Government Regulation	9
	California Natural Gas Utility Operations	12
	Electric Utility Operations	14
	Rates and Regulation – Utilities	18
	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	24
Item 1B.	Unresolved Staff Comments	44
Item 2.	Properties	44
Item 3.	Legal Proceedings	45
Item 4.	Mine Safety Disclosures	45

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Financial Data	47
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	47
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 8.	Financial Statements and Supplementary Data	47
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	47
Item 9A.	Controls and Procedures	47
Item 9B.	Other Information	47

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	48
Item 11.	Executive Compensation	48
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	48
Item 13.	Certain Relationships and Related Transactions, and Director Independence	48
Item 14.	Principal Accountant Fees and Services	49

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	51

Sempra Energy: Consent of Independent Registered Public Accounting Firm and Report on Schedule		52
San Diego Gas & Electric Company: Consent of Independent Registered Public Accounting Firm		53
Southern California Gas Company: Consent of Independent Registered Public Accounting Firm		54

Schedule I – Sempra Energy Condensed Financial Information of Parent		55

Signatures		60
Exhibit Index		63
Glossary		73

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,” “forecasts,” “contemplates,” “intends,” “assumes,” “depends,” “should,” “could,” “would,” “will,” “confident,” “may,” “potential,” “possible,” “proposed,” “target,” “pursue,” “goals,” “outlook,” “maintain,” or similar expressions, or when we discuss our guidance, strategy, plans, goals, opportunities, projections, 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, legal and regulatory conditions, decisions and developments;

actions and the timing of actions, including general rate case decisions, new regulations, issuances of permits to construct, operate, and maintain facilities and equipment and to use land, franchise agreements and licenses for operation, by the California Public Utilities Commission, California State Legislature, U.S. Department of Energy, California Division of Oil, Gas, and Geothermal Resources, Federal Energy Regulatory Commission, Nuclear Regulatory Commission, California Energy Commission, U.S. Environmental Protection Agency, Pipeline and Hazardous Materials Safety Administration, California Air Resources Board, South Coast Air Quality Management District, Mexican Competition Commission, cities and counties, and other regulatory, governmental and environmental bodies in the United States and other countries in which we operate;

the timing and success of business development efforts and construction, maintenance and capital projects, including risks in obtaining, maintaining or extending permits, licenses, certificates and other authorizations on a timely basis and risks in obtaining adequate and competitive financing for such projects;

§	deviations from regulatory precedent or practice that result in a reallocation of benefits or burdens among shareholders and ratepayers, and delays in regulatory agency authorization to recover costs in rates from customers;

the availability of electric power, natural gas and liquefied natural gas, and natural gas pipeline and storage capacity, including disruptions caused by failures in the North American transmission grid, moratoriums on the ability to withdraw natural gas from or inject natural gas into storage facilities, pipeline explosions and equipment failures;

energy markets; the timing and extent of changes and volatility in commodity prices; and the impact on the value of our natural gas storage assets from low natural gas prices, low volatility of natural gas prices and the inability to procure favorable long-term contracts for natural gas storage services;

§	the resolution of civil and criminal litigation and regulatory investigations;

§	risks posed by decisions and actions of third parties who control the operations of investments in which we do not have a controlling interest, and risks that our partners or counterparties will be unable or unwilling to fulfill their contractual commitments;

§	capital markets conditions, including the availability of credit and the liquidity of our investments, and inflation, interest and currency exchange rates;

cybersecurity threats to the energy grid, natural gas storage and pipeline infrastructure, the information and systems used to operate our businesses and the confidentiality of our proprietary information and the personal information of our customers and employees; terrorist attacks that threaten system operations and critical infrastructure; and wars;

§	the ability to win competitively bid infrastructure projects against a number of strong competitors willing to aggressively bid for these projects;

weather conditions, natural disasters, catastrophic accidents, equipment failures and other events that may disrupt our operations, damage our facilities and systems, cause the release of greenhouse gasses, radioactive materials and harmful emissions, and subject us to third-party liability for property damage or personal injuries, some of which may not be covered by insurance;

§	disallowance of regulatory assets associated with, or decommissioning costs of, the San Onofre Nuclear Generating Station facility due to increased regulatory oversight, including motions to modify settlements;

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

§	the impact on reliability of San Diego Gas & Electric Company’s (SDG&E) electric transmission and distribution system due to increased amount and variability of power supply from renewable energy sources and increased reliance on natural gas and natural gas transmission systems;

§	the impact on competitive customer rates of the growth in distributed and local power generation and the corresponding decrease in demand for power delivered through SDG&E’s electric transmission and distribution system;

§	the inability or determination not to enter into long-term supply and sales agreements or long-term firm capacity agreements due to insufficient market interest, unattractive pricing or other factors; 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” and additional information by reporting segment in Note 16 of the Notes to Consolidated Financial Statements, both in the 2015 Annual Report to Shareholders (Annual Report), which is attached as Exhibit 13.1 to this report and is incorporated herein 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 capital stock of SDG&E and all of the common stock and substantially all of the voting stock of SoCalGas.

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.

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 – www.sempra.com

SDG&E – www.sdge.com

SoCalGas – 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, 488 8th Avenue, San Diego, CA 92101-7123.

The SEC also maintains a website that contains reports, proxy and information statements and other information we file with the SEC at www.sec.gov. Copies of these reports, proxy and information statements and other information may also be obtained, after paying a duplicating fee, by electronic request at certified@sec.gov, or by writing the SEC’s Public Reference Room, 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330.

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

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 safety, 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.

The CPUC also oversees and regulates new products and services, including solar and wind energy, bioenergy and other forms of renewable energy. In addition, the CPUC’s safety and enforcement role includes inspections, investigations and penalty and citation processes for safety violations.

We provide further discussion in Notes 13 and 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 on 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 to reduce demand within the state of California for electricity and natural gas;

§	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.

The state of California requires certain California electric retail sellers, including SDG&E, to deliver a percentage 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. The 33% RPS Program requires each electric utility within the state of California 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 from January 1, 2011 through December 31, 2013; 25 percent by December 31, 2016; and 33 percent by December 31, 2020. In October 2015, California Senate Bill 350 was signed into law, requiring each electric utility within the state of California to procure 50 percent of its annual electric energy requirements from renewable energy sources by 2030, with interim targets of 40 percent by the end of 2024, and 45 percent by the end of 2027. 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 is certified as an ERR. Sempra Renewables has 50-percent interests in the Copper Mountain Solar 2, Copper Mountain Solar 3 and Mesquite Solar 1 facilities, as well as four solar facilities that comprise a California solar partnership with our joint venture partner, all of which have ERR certification. Sempra Renewables has received pre-certification for the Mesquite Solar 2, Mesquite Solar 3 and Copper Mountain Solar 4 facilities and is submitting applications for ERR certification of each phase of the projects as they begin operations. 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 (AB) 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. Sempra Natural Gas and Sempra Mexico are also subject to the rules and regulations of CARB. We provide further discussion in Note 1 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. The National Energy Policy Act governs procedures for requests for transmission service. The FERC approved the California investor-owned utilities’ (IOUs) transfer of operation and control of their transmission facilities to the Independent System Operator (ISO) in 1998.

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, operation and decommissioning 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. The majority owner of SONGS, Southern California Edison Company (Edison), made a decision to permanently retire the facility in June 2013. We provide further discussion of current SONGS matters involving the NRC and the closure of the facility in Note 13 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. See “Other U.S. Regulation” below.

State and Local Regulation Within the U.S.

In addition to regulation by the FERC, SoCalGas’ natural gas storage facilities are regulated by the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR), the CPUC, the CARB, and various other state and local agencies.

The South Coast Air Quality Management District (SCAQMD) is the air pollution control agency responsible for regulating stationary sources of air pollution in the South Coast Air Basin in Southern California. The district’s territory covers all of Orange County and the urban portions of Los Angeles, San Bernardino and Riverside counties.

SoCalGas has natural gas franchises with the 12 counties and the 223 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 2016 to 2062. Major franchise agreements include those for Los Angeles County and the City of Los Angeles. The Los Angeles County franchise agreement was entered into in 1955, with the current extension expiring in December 2017. The City of Los Angeles franchise was entered into in 1992, with the current extension expiring in June 2016.

SDG&E has

§	electric franchises with the two counties served 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 2016 to 2037.

Sempra Renewables has operations, investments or development projects in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Minnesota, Nebraska, Nevada and Pennsylvania. Sempra Natural Gas develops and operates natural gas storage and related pipeline facilities in Alabama, Louisiana and Mississippi, and has marketing operations in California.

Sempra Natural Gas 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 ten cities in its service territory, with fixed expiration dates ranging from 2016 to 2045, which allow it to locate, operate and maintain facilities for the transmission and distribution of natural gas. 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

FERC regulates certain Sempra Renewables and Sempra Natural Gas assets pursuant to the Federal Power Act (FPA) and Natural Gas Act, which provide for FERC jurisdiction over, among other things, sales of wholesale power in interstate commerce, transportation and storage of natural gas in interstate commerce, and siting and permitting of liquefied natural gas (LNG) terminals. In addition, certain Sempra Renewables power generation assets are required under the FPA to comply with reliability standards developed by the North American Electric Reliability Corporation. Bay Gas Storage Company, Ltd.’s natural gas storage operations are also regulated by the Alabama Public Service Commission.

Sempra Natural Gas also owns an interest in the Rockies Express pipeline (REX), a natural gas pipeline that operates in eight states in the United States and is subject to regulation by the FERC. Sempra Natural Gas also has an investment in Cameron LNG Holdings, LLC (Cameron LNG JV), located in Louisiana, that is subject to regulations of the U.S. Department of Energy (DOE) regarding the export of LNG. We discuss Sempra Natural Gas’ investments 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. 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 (at Cameron LNG JV) and the purchase and sale of LNG and natural gas

The California Utilities, Sempra Natural Gas and businesses that Sempra Natural Gas invests in are subject to DOT rules and regulations regarding pipeline safety, under the Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA, acting through the Office of Pipeline Safety, is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipeline and develops regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance, and emergency response of pipeline facilities. The California Utilities and Sempra Natural Gas are also subject to regulation by the U.S. Commodity Futures Trading Commission.

Foreign Regulation

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

a natural gas-fired power plant and a 50-percent interest in a wind generation facility in Baja California, Mexico; in February 2016, management approved a plan to market and sell the natural gas-fired power plant, as we discuss in Note 18 of the Notes to Consolidated Financial Statements in the Annual Report

§	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 (Petróleos Mexicanos, the Mexican state-owned oil company) that operates several natural gas pipelines and propane and ethane systems in Mexico. We discuss Sempra Mexico’s potential acquisition of PEMEX’s 50-percent interest in the joint venture in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report

§	the Energía Costa Azul LNG regasification 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 Mexico’s operations in Mexico are contained in the Sempra Energy subsidiary Infraestructura Energética Nova, S.A.B. de C.V. (IEnova). In the first quarter of 2013, IEnova completed a private offering in the U.S. and outside of Mexico and concurrent public offering in Mexico of common stock. The issuance of shares was approved and is subject to regulation by the Mexican National Banking and Securities Commission (Comisión Nacional Bancaria y de Valores, or CNBV) for registration of the shares with the Mexican National Securities Registry (Registro Nacional de Valores, or RNV) maintained by the CNBV. IEnova’s shares are traded on the Mexican Stock Exchange (La Bolsa Mexicana de Valores, S.A.B. de C.V., or BMV) under the symbol “IENOVA.”

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 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.

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, including electric generation and natural gas storage facilities, some of which may require periodic renewal.

Sempra Mexico and Sempra South American Utilities obtain numerous permits, authorizations and licenses for their electric and natural gas distribution, generation and transmission systems from the local governments where the service is provided. The concession to operate from the Ministerio de Energía for both Chilquinta Energía’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 natural gas storage facilities and pipelines, and with participation in the wholesale electricity market.

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 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. We discuss the California Utilities’ resource planning, natural gas procurement, contractual commitments, and related regulatory matters 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, 2015, SoCalGas had approximately 5.9 million customer meters consisting of approximately:

§	5,621,600 residential

§	252,900 commercial

§	26,300 industrial

§	50 electric generation and wholesale

At December 31, 2015, SDG&E had approximately 873,000 natural gas customer meters consisting of approximately:

§	839,600 residential

§	28,500 commercial

§	4,700 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 and industrial, and enhanced oil recovery customers. SoCalGas’ wholesale customers are primarily other IOUs, including SDG&E, or municipally owned natural gas distribution systems. Noncore customers at SDG&E consist primarily of electric generation and large commercial 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 2015, SoCalGas added approximately 33,000 new connected natural gas customer meters, representing an annual growth rate of 0.6 percent; in 2014, it added approximately 26,000 new connected meters, representing an annual growth rate of 0.4 percent. SDG&E’s connected natural gas customer meters increased by approximately 5,000 in 2015, representing an annual growth rate of 0.6 percent; in 2014, it added nearly 3,000 new connected meters, representing an annual growth rate of 0.4 percent. Based on forecasts of new housing starts, SoCalGas and SDG&E each expect that their new meter annual growth rates in 2016 will be slightly higher than those achieved in 2015.

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 supply 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. These contracts expire on various dates between 2016 and 2031. Pipeline companies, primarily El Paso Natural Gas Company, Transwestern Pipeline Company, Pacific Gas and Electric Company (PG&E) 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. The FERC regulates the rates that interstate pipeline companies may charge for natural gas and transportation services.

Natural Gas Storage

SoCalGas owns four natural gas storage facilities. The facilities have a combined working gas capacity of 137 billion cubic feet (Bcf) and have over 200 injection, withdrawal and observation wells. Natural gas withdrawn from storage is important for ensuring service reliability during peak demand periods, including heating needs in the winter, as well as peak electric generation needs in the summer. The Aliso Canyon natural gas storage facility represents 63 percent of SoCalGas’ owned natural gas storage capacity. SoCalGas discovered a natural gas leak at the Aliso Canyon facility in October 2015, which was permanently sealed in February 2016, as we discuss in “Risk Factors” below and in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report. SCAQMD has ordered SoCalGas to stop all injections at Aliso Canyon, subject to contrary CPUC reliability-based direction. The CPUC has directed SoCalGas to maintain a minimum of 15 Bcf of working natural gas to help ensure reliability of the system through the spring and summer months and based upon the CARB estimates of lost gas, the facility is approximately at this level. As a result, SoCalGas is no longer withdrawing gas from this facility. Now that the well has been permanently sealed, SoCalGas will conduct measurements to estimate the actual natural gas lost from the leak and will provide that information to the relevant regulatory bodies.

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 generation, legislation, and the effectiveness of energy efficiency programs. Other external factors such as weather, the price of electricity, the use of hydroelectric power, development of renewable energy resources, development of new natural gas supply sources, demand for natural gas outside the state of California, 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 price spread between delivered natural gas and potential fuel alternatives.

Natural gas-fired electric generation within Southern California (and demand for natural gas supplied to such plants) competes with electric power generated throughout the western United States. Natural gas transported for electric generating plant customers may be affected by the growth in renewable generation (including rooftop solar), the addition of more efficient gas technologies, new energy efficiency initiatives, and the extent that regulatory changes in 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 due to climate change, weather conditions and other impacts, 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 and related infrastructure projects and regulatory impacts at the California Utilities in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

The natural gas distribution business is seasonal, and cash provided from operating activities generally is greater during and immediately following the winter heating months. As is prevalent in the industry, SoCalGas injects natural gas into storage during the summer months (usually April through October), which reduces cash provided from operating activities during this period, for withdrawal from storage during the winter months (usually November through March), which increases cash provided from operating activities, when customer demand is higher. SCAQMD has issued a temporary moratorium to SoCalGas prohibiting the injection of natural gas into the Aliso Canyon storage facility, as we discuss in Risk Factors below.

ELECTRIC UTILITY OPERATIONS

SDG&E

Customers

SDG&E’s service area covers 4,100 square miles. At December 31, 2015, SDG&E had approximately 1.4 million electric customer meters consisting of approximately:

§	1,268,700 residential

§	150,100 commercial

§	500 industrial

§	5,100 direct access

§	2,000 street and highway lighting

SDG&E’s active electric customer meters increased by approximately 9,800 and 8,000 in 2015 and 2014, respectively, representing annual growth rates of 0.7 percent and 0.6 percent, respectively. Based on forecasting of new housing starts, SDG&E expects that its new meter annual growth rate in 2016 will be slightly higher than the growth in 2015.

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 various suppliers, SDG&E’s wholly owned generating facilities, and purchases on a spot basis. This supply as of December 31, 2015 is as follows:

SDG&E ELECTRIC RESOURCES

Resource		Number of contracts	Expiration date	Megawatts
PURCHASED-POWER CONTRACTS:
Contracts with Qualifying Facilities (QFs)(1):
	Cogeneration	6	2016 and thereafter	139
	Cogeneration tolling contracts(2)	2	2024, 2025	101
	Total			240

Other contracts with renewable sources:
	Wind	13	2018 to 2035	1,234
	Solar PV	16	2033 to 2039	930
	Bio-gas/Hydro	16	2016 and thereafter	39
	Total			2,203

Tolling(2) and other contracts:
	Natural gas tolling contracts	4	2019 to 2039	800
	Hydro/Pump storage	1	2037	40
	Demand response/Distributed generation	1	2016	25
	Market(3)	2	2016, 2019	243
	Total			1,108
Total contracted				3,551

OWNED GENERATION, NATURAL GAS:
	Palomar Energy Center			565
	Desert Star Energy Center			480
	Miramar Energy Center			96
	Cuyamaca Peak Energy Plant			45
Total owned generation				1,186
TOTAL CONTRACTED AND OWNED GENERATION				4,737
(1)	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.
(2)	Tolling contracts are purchased-power agreements under which SDG&E provides natural gas for generation to the energy supplier.
(3)	Agreements to purchase firm energy during specific periods at fixed prices.

Charges 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, Desert Star, Miramar and Cuyamaca Peak generating facilities and for the Otay Mesa Energy Center LLC, Orange Grove Energy L.P., El Cajon Energy, LLC, Escondido Energy Center, LLC and Goal Line L.P. 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, 2017. 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, 2017. SDG&E has also contracted with SoCalGas for natural gas storage through March 31, 2016. This is a year-to-year contract with a term of April through March that is renegotiated annually.

Power Pool

SDG&E is a participant in the Western Systems Power Pool, which includes an electric-power and transmission-rate agreement that allows access to power trading with more than 300 member utilities, power agencies, energy brokers and power marketers located throughout the United States and Canada. Participants are able to make power transactions on standardized terms, including market-based rates, preapproved by the FERC. Participation in the Western Systems Power Pool is intended to assist members in managing power delivery and price risk.

Transmission System and Access

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 megawatts (MW), although it can be less under certain system conditions.

SDG&E’s Sunrise Powerlink is a 500-kV transmission line constructed and operated by SDG&E with import capability of 1,000 MW of power. It provides transmission capability into SDG&E’s service territory for renewable energy generated at various renewable energy generation facilities located in the Imperial Valley region of Southern California. We provide further discussion of Sunrise Powerlink in Notes 14 and 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.

We provide additional information regarding transmission matters in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

Chilquinta Energía

Customers

Chilquinta Energía has approximately 672,000 customer meters 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, 2015, its customer meters consisted of approximately:

§	620,200 residential

§	38,300 commercial

§	1,400 industrial

§	7,100 street and highway lighting

§	5,200 agricultural

In Chile, customers are 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 2015, Chilquinta Energía added approximately 15,000 new customer meters at a growth rate of 2.3 percent. Chilquinta Energía’s electric energy sales decreased by approximately 57,000 megawatt hours (MWh) and increased by approximately 88,000 MWh in 2015 and 2014, respectively, representing a decline in annual growth rate of 1.9 percent in 2015 and an increase of 3 percent in 2014. The decrease in electric energy sales in 2015 is primarily due to the transfer of certain non-regulated customers from Chilquinta Energía to the energy-services company, Tecnored S.A., a subsidiary of Sempra South American Utilities in Chile.

Electric Resources

The supply of electric power available to Chilquinta Energía comes from purchased-power contracts currently in place with its various suppliers and its suppliers’ generating facilities. This supply as of December 31, 2015 was as follows:

CHILQUINTA ENERGÍA ELECTRIC RESOURCES

Resource		Number of contracts	Expiration date	Megawatts
PURCHASED-POWER CONTRACTS(1)(2):
	Thermal/Hydro/Wind/Solar	18	2020 to 2026	439

SMALL GENERATION PLANTS:
	Thermal			11
TOTAL				450
(1)	Contracts with fuel sources that include natural gas, coal or diesel are collectively referred to as thermal.
(2)	In 2015, energy contracts in the Central Interconnected System, where Chilquinta Energía operates, were supplied 50 percent from thermal, 45 percent from hydro, 3 percent from wind and 2 percent from solar sources.

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

Transmission lines in Chile are either part of its main transmission system (sistema de transmisión troncal) or its sub-transmission system (sistema de subtransmisión). In Chile, main transmission lines must be greater than or equal to 220 kV. Chilquinta Energía primarily uses Transelec, a third party, for its main transmission. In general, sub-transmission systems operate at voltage levels greater than 23 kV and lower than or equal to 220 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 and regulated end-users located in the distribution service area.

We discuss transmission line projects that were completed in 2015 or are ongoing at Chilquinta Energía’s joint ventures in the “Our Business” and “Factors Influencing Future Performance” sections of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

Luz del Sur

Customers

Luz del Sur has approximately 1,053,000 customer meters in the southern zone of metropolitan Lima, Peru, with a main service area covering approximately 1,394 square miles. At December 31, 2015, its customer meters consisted of approximately:

§	987,300 residential

§	55,900 commercial

§	4,000 industrial

§	5,000 street and highway lighting

§	500 agricultural

In Peru, customers are 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. Non-regulated customers are those whose capacity demand is greater than 2,500 kW. Customers with capacity demand between 200 kW and 2,500 kW may choose to be classified as regulated or non-regulated.

In 2015, Luz del Sur added approximately 24,000 new customer meters at a growth rate of 2.3 percent. Luz del Sur’s electric energy sales increased by approximately 262,000 MWh and 303,000 MWh in 2015 and 2014, respectively, representing annual growth rates of 3.6 percent in 2015 and 4 percent in 2014.

Electric Resources

The supply of electric power available to Luz del Sur comes from purchased-power contracts currently in place with various suppliers, as well as purchases made on an as-needed basis. Starting in September 2015, Luz del Sur also began using the supply of power generated by Santa Teresa, its wholly owned 100-MW hydroelectric power plant in Peru’s Cusco region.

Luz del Sur’s electric power supply as of December 31, 2015 was as follows:

LUZ DEL SUR ELECTRIC RESOURCES

Resource		Number of contracts	Expiration date	Megawatts
PURCHASED-POWER CONTRACTS(1):
Auction contracts:
	Hydro	12	2021 to 2025	378
	Thermal	10	2021 to 2025	889
	Hydro/Thermal	3	2021 to 2025	231
	Total contracted			1,498

OWNED GENERATION, HYDRO:
	Santa Teresa(2)			59
TOTAL CONTRACTED AND OWNED GENERATION				1,557
(1)	Contracts with fuel sources that include natural gas, coal or diesel are collectively referred to as thermal.
(2)	Firm capacity is estimated at 59 MW based on guidelines established by the system operator in Peru and historical water flows. Available excess capacity is sold on the spot market.

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, in addition to setting tariffs as discussed above, controls and enforces compliance with legal and technical regulations related to electric activities and supervises the bidding processes required by distribution companies to purchase energy from generators.

The Committee of Economic Operation of the National Interconnected 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 as 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.

We discuss ongoing transmission line and substation projects at Luz del Sur in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance” in the Annual Report.

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, 13 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 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. Sempra Renewables will compete with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, and other energy service companies for sales of non-contracted renewable energy when its Copper Mountain Solar 4 facility is placed in service in 2016 until a 20-year power sales agreement with Edison begins in 2020. The number and type of competitors may vary based on location, generation type and project size. Also, 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 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:

§ Avangrid (formerly Iberdrola)

§ First Solar

§ Invenergy

§ MidAmerican Energy

§ NextEra Energy Resources

§ NRG Energy

§ SunEdison

Because Sempra Mexico sells the power that it generates at its Energía Sierra Juárez wind project 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:

§ AGL Resources

§ Avangrid (formerly Iberdrola)

§ Boardwalk Pipeline Partners

§ Cardinal Gas Storage Partners

§ Clean Energy

§ Duke Energy

§ Enbridge

§ Energy Transfer Partners

§ Enterprise Products Partners

§ Kinder Morgan

§ Macquarie Infrastructure Partners

§ NiSource

§ Plains All American Pipeline

§ Spectra Energy

§ TransCanada

§ The Williams Companies

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

§ Carso Energy

§ Enagas

§ Energy Transfer

§ Fermaca

§ ENGIE S.A. (formerly GDF SUEZ S.A.)

§ Kinder Morgan

§ Mitsui

§ Cenagas

§ TransCanada

LNG

Technological advances associated with shale gas and tight oil production have eliminated the need for North American LNG import facilities and increased interest in liquefaction and export opportunities.

At current forward gas prices, U.S. Gulf Coast liquefaction is among the most price competitive potential LNG supply in the world. Brownfield liquefaction is particularly price competitive, resulting from many factors, including:

§	high levels of undeveloped North American unconventional natural gas and tight oil resources relative to domestic consumption levels;

§	increasing gas and oil drilling productivity and decreasing unit costs of gas production;

§	low breakeven prices of marginal North American unconventional gas production;

§	proximity to ample existing gas transmission pipeline and underground gas storage capacity; and

§	existing LNG tankage and berths.

Global LNG competition, primarily from Canada, Russia, East Africa and Australia, may limit U.S. LNG exports, as international liquefaction projects attempt to match U.S. Gulf Coast LNG production costs and customer contractual rights such as volume and destination flexibility. Host governments for international liquefaction projects are altering fiscal and tax regimes in an effort to make projects in their jurisdictions competitive relative to U.S. projects; however, sustained low oil prices may cause some of the international projects to become unfeasible due to their LNG price formulas’ link to oil prices. It is expected that U.S. LNG exports will increase competition for current and future global natural gas demand, and thereby facilitate development of a global commodity market for natural gas.

Sempra Natural Gas has a 50.2-percent equity interest in Cameron LNG JV, which owns a regasification facility in Hackberry, Louisiana. The joint venture began construction in the second half of 2014 on a natural gas liquefaction export facility using some of the existing regasification infrastructure. The joint venture has authorization to export LNG to both Free Trade Agreement (FTA) countries and to countries that do not have an FTA with the United States.

Cameron LNG JV has 20-year liquefaction and regasification tolling capacity agreements in place with ENGIE S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd., which subscribe the full nameplate capacity of three trains at the facility. In addition, Cameron LNG JV is working on the development of up to two additional trains. These projects would compete against other global projects. We discuss Cameron LNG JV in Notes 3 and 4 of the Notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance” in the Annual Report. Our joint venture partners, affiliates of ENGIE S.A., Mitsubishi Corporation (through a related company jointly established with Nippon Yusen Kabushiki Kaisha (NYK)), and Mitsui & Co., Ltd., 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, Cameron LNG JV will compete indirectly with liquefaction projects currently operating and those under development in the global LNG market. In addition to the U.S., these competitors are located in the Middle East, Southeast Asia, Africa, South America, Australia and Europe.

Sempra Energy is also taking steps to develop additional LNG export facilities at Sempra Natural Gas’ Port Arthur, Texas property and Sempra Mexico’s Energía Costa Azul regasification facility.

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

§ BG § BP	§ Kinder Morgan § Petronas
§ Cheniere Energy	§ Qatar Petroleum
§ Chevron	§ Royal Dutch Shell
§ ConocoPhillips	§ Total
§ ExxonMobil	§ Woodside

ENVIRONMENTAL MATTERS

We discuss environmental issues affecting us in Note 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

The CPUC’s Hazardous Waste Collaborative mechanism allows 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, 2015, we had accrued estimated remaining investigation and remediation liabilities of $2 million at SDG&E and $25 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. 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), the CARB and SCAQMD. The California Utilities generally recover in rates the costs to comply with these standards. We discuss greenhouse gas standards and credits further in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

In connection with the issuance of operating permits, SDG&E and the other owners of SONGS have an agreement with the California Coastal Commission (CCC) to mitigate environmental impacts to the marine environment attributed to the cooling-water discharge from SONGS during its operation. SONGS’ early retirement, described in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report, does not reduce SDG&E’s mitigation obligation. SDG&E’s share of the mitigation costs is estimated to be $57 million, of which $43 million had been incurred through December 31, 2015, and $14 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 CCC accepts the projects. The remaining costs are to meet CCC acceptance requirements and maintain the projects through 2050.

We discuss SoCalGas’ Aliso Canyon natural gas storage facility in “Risk Factors” below, and in “Factors Influencing Future Performance” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

EXECUTIVE OFFICERS OF THE REGISTRANTS

EXECUTIVE OFFICERS OF SEMPRA ENERGY

Name	Age(1)	Position(1)
Debra L. Reed	59	Chairman and Chief Executive Officer
Mark A. Snell	59	President
Joseph A. Householder	60	Executive Vice President and Chief Financial Officer
Martha B. Wyrsch	58	Executive Vice President and General Counsel
Steven D. Davis	60	Executive Vice President - External Affairs and Corporate Strategy
Trevor I. Mihalik	49	Senior Vice President, Controller and Chief Accounting Officer
G. Joyce Rowland	61	Senior Vice President, Chief Human Resources Officer and Chief Administrative
		Officer
(1) Ages and positions are as of February 26, 2016.

With the exception of Ms. Wyrsch and 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 September 2013, Ms. Wyrsch served as President of Vestas American Wind Systems from 2009 to 2012. Previously, Ms. Wyrsch spent nearly ten years at Duke Energy and its spinoff, Spectra Energy Corporation. She joined Duke Energy in 1999 as Senior Vice President of Legal Affairs and Deputy Counsel and, later, was promoted to Group Vice President and General Counsel. In 2005, she moved to Duke Energy Gas Transmission as its President and Chief Executive Officer. Subsequently, she became the President and Chief Executive Officer of Spectra Energy Transmission.

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.

EXECUTIVE OFFICERS OF SDG&E AND SOCALGAS

Name	Age(1)	Position(1)
San Diego Gas & Electric Company:
J. Walker Martin	54	Chairman, President and Chief Executive Officer
James P. Avery	59	Chief Development Officer
J. Chris Baker	56	Chief Information Officer
Lee Schavrien	61	Chief Administrative Officer
Erbin B. Keith	55	Senior Vice President and General Counsel
Bruce Folkmann	48	Vice President, Controller, Chief Financial Officer, Chief Accounting Officer
		and Treasurer
Southern California Gas Company:
Dennis V. Arriola	55	Chairman, President and Chief Executive Officer
J. Bret Lane	56	Chief Operating Officer
J. Chris Baker	56	Chief Information Officer
Lee Schavrien	61	Chief Administrative Officer
Sharon L. Tomkins	50	Vice President and General Counsel
Bruce Folkmann	48	Vice President, Controller, Chief Financial Officer, Chief Accounting Officer
		and Treasurer
(1) Ages and positions are as of February 26, 2016.

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.

Since joining Sempra Energy in 2005, Mr. Folkmann has held positions of increasing responsibility in the accounting and finance organization. Prior to his current position, Mr. Folkmann was the Vice President & Chief Financial Officer for Sempra U.S. Gas & Power, a subsidiary of Sempra Energy.

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 period. 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 Corporation. In August 2012, he joined SoCalGas as President and Chief Operating Officer, and in December 2012, he also joined the SoCalGas board of directors.

OTHER MATTERS

Employees of the Registrants

At December 31, each company has the following number of employees:

NUMBER OF EMPLOYEES

		December 31,
		2015	2014
Sempra Energy Consolidated(1)		17,387	17,046
SDG&E(1)		4,315	4,300
SoCalGas		8,438	8,324
(1)	Excludes employees of variable interest entities as defined by accounting principles generally accepted in the United States of America.

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 provisions of the collective bargaining agreement for these employees covering wages, hours, working conditions, medical and all other benefit plans are in effect through September 30, 2018. At December 31, 2015, 67 percent of SoCalGas employees are represented by the Union.

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 covering wages and working conditions for these employees are in effect through August 31, 2020 (subject to wage renegotiation on September 1, 2019). For these same employees, the agreement covering pension and savings plan benefits is in effect through October 1, 2017 and the agreement covering health and welfare benefits is in effect through December 31, 2016. At December 31, 2015, 29 percent of SDG&E employees are covered by these agreements.

Sempra South American Utilities

Field, technical and administrative employees at Luz del Sur are represented by the Unified Trade Union of Electricity Workers of Lima and Callao, and the Trade Union of Employees of Electrolima. In February 2016, two collective bargaining agreements were signed covering these employees, which will also be extended to 138 nonrepresented employees. It will cover wages, working conditions and other benefit plans, and will be in effect from January 1, 2016 through December 31, 2016.

Field, technical and administrative employees at Chilquinta Energía are represented by Labor Union Number 1 Chilquinta Energía, Labor Union Number 2 Chilquinta Energía, Litoral Labor Union, Luzlinares Labor Union, Tecnored Labor Union Number 1, Negotiating Group Luzparral and Negotiating Group Casablanca. The collective bargaining agreements for employees represented by these unions and negotiating groups cover wages, hours, working conditions and medical and other benefit plans and are in effect through 2016 and 2019.

Professional employees at Chilquinta Energía are represented by Professional Union. The collective bargaining agreement for these employees covers wages, hours, working conditions and medical and other benefit plans and is in effect through July 2, 2017.

At December 31, 2015, Sempra South American Utilities has a total of 1,378 employees in Peru, of whom 24 percent are covered under a labor agreement, and 1,441 employees in Chile, of whom 41 percent are covered under labor agreements.

Sempra Mexico

At December 31, 2015, Sempra Mexico has 639 employees, 6 percent of whom are covered by various collective bargaining agreements with different labor unions. The collective bargaining agreements are subject to renegotiation 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, 2017. At December 31, 2015, Mobile Gas has a total of 215 employees, 34 percent of whom are covered under this agreement.

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 prices of our securities and those of our subsidiaries 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, as the case may be, have a material adverse effect on our businesses, cash flows, results of operations, financial condition, prospects and/or the trading prices of our securities or those of our subsidiaries.

Sempra Energy’s cash flows, ability to pay dividends and ability to meet its debt obligations largely depend on the performance of its subsidiaries and the ability to utilize the cash flows from those 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 expenditures, preferred stock dividends (if any), and long-term debt obligations. In addition, the subsidiaries are separate and distinct legal entities that are not obligated to pay dividends 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.

A significant portion of our worldwide cash reserves are generated by, and therefore held in, foreign jurisdictions. Some jurisdictions restrict the amount of cash that can be transferred to the United States or impose taxes on such transfers of cash, which reduces the cash available to us. In addition, we may be required to pay U.S. income taxes on earnings that are not repatriated if legislation being discussed on this matter is passed. To the extent we have excess cash in foreign locations that could be used in, or is needed by, our United States operations, we may incur significant U.S. and foreign taxes to repatriate these funds.

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.

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 market environments, 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 new business activities. This could cause us to reduce capital expenditures and could increase our cost of servicing debt, 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 credit ratings could materially adversely affect the cash flows and results of operations of Sempra Energy and its regulated utility subsidiaries located outside of California. If the credit ratings of Sempra Energy or any of its subsidiaries were to decline, especially below investment grade, financing costs and the principal amount of borrowings would likely increase due to the additional risk of our debt and because certain counterparties may require collateral in the form of cash, a letter of credit or other forms of security for new and existing transactions. Such amounts may be material and could adversely affect our cash flows, results of operations and financial condition.

Sempra Energy has substantial investments in Mexico and South America which expose us to foreign currency, inflation, legal, tax, economic, geo-political and management oversight risk.

We have foreign operations in Mexico and South America. Our foreign operations pose complex management, foreign currency, legal, tax and economic risks, which we may not be able to fully mitigate with our actions. These risks differ from and potentially may be greater than those associated with our domestic businesses. All of our international businesses are sensitive to geo-political uncertainties, and our non-utility international businesses are sensitive to changes in the priorities and budgets of international customers, all of which may be driven by changes in threat environments and potentially volatile worldwide economic conditions, and various regional and local economic and political factors, risks and uncertainties, as well as U.S. foreign policy. Foreign currency exchange and inflation rates and fluctuations may have an impact on our revenue, costs or cash flows from our international operations, which could materially adversely affect our financial performance. Our primary currency exposures are to the Mexican, Peruvian and Chilean currencies. Our primary objective in reducing foreign currency risk is to preserve the economic value of our foreign investments and to reduce earnings volatility that would otherwise occur due to exchange rate fluctuations. We may attempt to offset material cross-currency transactions and earnings exposure through various means, including financial instruments and short-term investments. Because we generally do not hedge our net investments in foreign countries, we are susceptible to volatility in other comprehensive income caused by exchange rate fluctuations, primarily related to our South American subsidiaries, whose functional currency is not the U.S. dollar. We discuss our foreign currency exposure at our Mexican subsidiaries in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes – Foreign Currency Exchange Rate and Inflation Impact on Income Taxes and Related Economic Hedging Activity” and “Factors Influencing Future Performance – Market Risk – Foreign Currency Rate Risk” in the Annual Report.

Risks Related to All Sempra Energy Subsidiaries

Severe weather conditions, natural disasters, catastrophic accidents, major equipment failures 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 severe weather conditions, natural disasters such as earthquakes, tsunamis and fires, catastrophic accidents, major equipment failures 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 risks such incidents may pose to our facilities and infrastructure, as well as the risks to the surrounding communities, are substantially greater than the risks such incidents may pose to a typical business. The facilities and infrastructure that we own and in which we have interests that may be subject to such incidents include, but are not limited to:

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

Such incidents could result in severe business disruptions, property damage, injuries or loss of life, significant decreases in revenues and earnings, 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; natural gas odorant; propane or ethane leaks; radioactive releases; explosions, spills or other significant damage to natural resources or property belonging to third parties; personal injuries, health impacts or fatalities; or present a nuisance to impacted communities. 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 due to the existence of limitations, exclusions, high deductibles, failure to comply with procedural requirements, and other factors, which could materially adversely affect our businesses, financial condition, results of operations, cash flows and/or prospects.

Severe weather conditions may also impact our businesses, including our international operations. On January 17, 2014, the Governor of California declared a state of emergency because of severe drought conditions in the state. The drought conditions in California and the western United States increase the risk of catastrophic wildfires in SDG&E’s and SoCalGas’ service territories, which could place third party property and our electric and natural gas infrastructure in jeopardy. The drought conditions also reduce the amount of power available from hydro-electric generation facilities in the Northwest United States, which could adversely impact the availability of a reliable energy supply into the California electric grid managed by the California ISO. If alternate supplies of electric generation are not available to replace the lower level of power available from hydro-electric generation facilities, this could result in temporary power shortages in SDG&E’s service territory.

Another example of weather impacting operations is a strong El Niño weather pattern in the Pacific Ocean, which has caused severe rainstorms in Southern California during the winter in late 2015 and early 2016, and could continue beyond that timeframe. Significant rainstorms and associated high winds, such as those caused by a strong El Niño weather pattern, could damage our electric and natural gas infrastructure, resulting in increased expenses, including higher maintenance and repair costs, and interruptions in electricity and natural gas delivery services. As a result, these events can have significant financial consequences, including regulatory penalties and disallowances if the California Utilities or our utilities in Mexico, South America, Alabama and Mississippi encounter difficulties in restoring service to their customers on a timely basis. Further, the cost of storm restoration efforts may not be fully recoverable through the regulatory process. Any such events could have a material adverse effect on our businesses, financial condition, results of operations and cash flows.

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 the federal, state and local 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.

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 in the U.S. and other countries in which we operate could materially adversely affect our tax expense and/or tax balances. Changes in regulations, laws and tariffs and how they 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 businesses. These rules are commonly referred to as “affiliate rules,” which primarily impact commodity and commodity-related transactions. These businesses could be materially adversely affected by changes in these rules or to their interpretations, or by additional CPUC or FERC rules that further restrict our ability to sell electricity or natural gas to, or to trade with, the California Utilities and with each other. Affiliate 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 on or approval requirements for transactions among affiliates 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, licenses, franchise agreements, and other governmental approvals from various federal, state, local and foreign governmental agencies; any failure to obtain or maintain required permits, licenses 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 distribution and storage facilities; electric generation, transmission and distribution facilities; and propane and ethane systems require numerous permits, licenses, franchise agreements, 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 or modified in litigation. In addition, permits, licenses, franchise agreements, certificates, and other approvals may be modified, rescinded or fail to be extended by one or more of the governmental agencies and authorities that oversee our businesses. SoCalGas’ franchise agreements for the City of Los Angeles and Los Angeles County, where the Aliso Canyon facility is located, are due to expire in 2016 and 2017, respectively. If there is a delay in obtaining any required regulatory approvals or failure 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. Further, accidents beyond our control may cause us to violate the terms of conditional use permits, causing delays in projects. Any such delay or failure to obtain or maintain necessary permits, licenses, certificates and other 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.

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.

Our businesses are subject to extensive federal, state, local and foreign statutes, rules and regulations and mandates relating to environmental protection, including, air quality, water quality and usage, wastewater discharge, solid waste management, hazardous waste disposal and remediation, conservation of natural resources, wetlands and wildlife, renewable energy resources, climate change and greenhouse gas, or 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 amounts on environmental monitoring, pollution control equipment, mitigation costs and emissions fees. The California Utilities may be materially adversely affected if these additional costs for projects are not recoverable in rates. In addition, we may be ultimately responsible for all on-site liabilities associated with the environmental condition of our LNG terminals, natural gas transmission, distribution and storage facilities, electric generation, transmission and distribution facilities and other energy projects and properties, regardless of when the liabilities arose and whether they are known or unknown. In the case of our California and other regulated utilities, some of these costs may not be recoverable in rates. Our facilities, including those in our joint ventures, are subject to laws and regulations protecting migratory birds, which have recently been the subject of increased enforcement activity with respect to wind farms. Failure to comply with applicable environmental laws, regulations and permits may subject our businesses 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 state, 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 non-utility 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, our California and other regulated 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 and may have a material adverse effect on the California Utilities’ cash flows. 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, orders and regulations regarding mercury, nitrogen and sulfur oxides, particulates, methane or other emissions could result in requirements for additional monitoring, pollution monitoring and control equipment, safety practices or emission fees, taxes or penalties 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.

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

Sempra Energy and its subsidiaries are defendants in numerous lawsuits and arbitration proceedings. We have spent, and continue to spend, substantial amounts of money and time defending these lawsuits and proceedings, and in related investigations and regulatory proceedings. We discuss pending 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 lawsuits, arbitrations and other legal proceedings make it difficult to estimate with any degree of certainty the costs and effects of resolving these matters. In addition, 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 in rates 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, natural gas storage and pipeline capacity and electric generation 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, possible changes in federal regulation of over-the-counter derivatives regulated by the U.S. Commodity Futures Trading Commission could impact the cost and effectiveness of our hedging programs, as we discuss in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance – Other Sempra Energy Matters” in the Annual Report. 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 those contracts. 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 our businesses 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 company-by-company 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. 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 implemented by us or developed by others present a risk for increased attacks on our information systems and the integrity of our energy grid and our natural gas pipeline and storage infrastructure.

Cybersecurity and the protection of our operations and other activities, including our customer and employee information, are a priority at Sempra Energy, SDG&E and SoCalGas. 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 evolving cybersecurity risks associated with protecting sensitive and confidential customer information, Smart Grid infrastructure, and natural gas pipeline and storage infrastructure. Deployment of new business technologies represents a new and large-scale opportunity for attacks on our information systems and confidential customer information, as well as on the integrity of the energy grid and the natural gas infrastructure. While our computer systems have been, and will likely continue to be, subjected to computer viruses or other malware, unauthorized access attempts, and cyber- or phishing-attacks, to date we have not experienced a material breach of cybersecurity. Addressing these risks is the subject of significant ongoing activities across Sempra Energy’s businesses, but we cannot ensure that a successful attack will not occur. An attack on our information systems, the integrity of the energy grid, our natural gas pipeline and storage infrastructure or one of our facilities, or unauthorized access to confidential customer information, could result in energy delivery service failures, financial loss, violations of privacy laws, customer dissatisfaction and litigation, any of which, in turn, could have a material adverse effect on our businesses, cash flows, financial condition, results of operations and/or prospects.

In the ordinary course of business, Sempra Energy and its subsidiaries collect and retain sensitive information, including personal identification information about customers and employees, customer energy usage and other information. The theft, damage or improper disclosure of sensitive electronic data can subject us to penalties for violation of applicable privacy laws, subject us to claims from third parties, require compliance with notification and monitoring regulations, and harm our reputation.

Finally, as seen with recent cyber-attacks around the world, the goal of a cyber-attack may be primarily to inflict large-scale harm on a company and the places where it operates. Any such cyber-attack could cause widespread disruptions to our operating and administrative systems, including the destruction of critical information and programming, that could materially adversely affect our business operations and the integrity of the power grid, and/or release confidential information about our company and our customers, employees and other constituents.

Our businesses will need to continue to adapt to technological change which may cause us to incur significant expenditures to adapt to these changes and which efforts may not be successful.

We expect that emerging technologies may be superior to, or may not be compatible with, some of our existing technologies, investments and infrastructure, and may require us to make significant expenditures to remain competitive, or may result in the obsolescence of certain of our operating assets or the operating assets of our equity method investments. Our future success will depend, in part, on our ability and our investment partners’ abilities to anticipate and successfully adapt to technological changes, to offer services that meet customer demands and evolving industry standards and to recover all, or a significant portion of, any unrecovered investment in obsolete assets. If we incur significant expenditures in adapting to technological changes, fail to adapt to significant technological changes, fail to obtain access to important new technologies, or fail to recover a significant portion of any remaining investment in obsolete assets, our businesses, operating results and financial condition could be materially and adversely affected. Examples of technological changes that could negatively impact our businesses include

§ California Utilities—Technologies that could change the utilization of natural gas distribution and electric generation, transmission and distribution assets including

□	energy storage technology, and

□	The expanded cost effective utilization of distributed generation (e.g., rooftop solar and community solar projects).

§ Sempra U.S. Gas & Power

□

At Sempra Renewables, technological advances in distributed and local power generation and energy storage could reduce the demand for large-scale renewable electricity generation. Sempra Renewables’ power sales customers’ ability to perform under long-term agreements could be impacted by changes in utility rate structures and advances in distributed and local power generation.

□	At Sempra Natural Gas, technological advances in alternative fuels and other alternative energy sources could reduce the demand for natural gas.

□

At our LNG businesses, technologies that lower global natural gas and LNG consumption would have the greatest impact on that business. These technologies include cost effective batteries for renewable electricity generation, economic improvements to gas-to-liquids conversion processes, and advances associated with seabed or Arctic gas hydrate exploitation.

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, safety standards and practices, 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 and storage and, for SDG&E, electric operations, under regulations concerning natural gas pipeline safety and citation programs concerning both gas and electric 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 Notes 13 and 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 CPUC periodically approves the California Utilities’ rates based on authorized capital expenditures, operating costs, including income taxes, and an authorized rate of return on investment. Delays by the CPUC on decisions authorizing recovery or authorizations for less than full recovery may adversely affect the working capital and financial condition of each of the California Utilities. If the California Utilities receive an adverse CPUC decision and/or actual capital expenditures and/or operating costs were to exceed the amounts approved by the CPUC, our 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 their results of operations, financial condition, cash flows and/or prospects.

The CPUC applies performance-based measures and mechanisms to all California utilities. Under these, earnings potential over authorized base margins is tied to achieving or exceeding specific performance and operating goals, and reductions in authorized base margins are tied to not achieving specific performance and operating goals. At both of the California Utilities, the areas that are currently eligible for performance mechanisms are operational activities designated by the CPUC and energy efficiency programs; at SDG&E, electric reliability performance; 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 legislation, regulations, decisions, orders or interpretations of the CPUC, the FERC or other regulatory bodies. In addition, existing legislation or regulations may be revised or reinterpreted. New, revised or reinterpreted legislation, regulations, decisions, orders or interpretations could change how the California Utilities 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 good 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. The California Utilities may invest a significant amount of money in 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 any or all amounts invested in that project, which could materially adversely affect their financial condition, results of operations, cash flows and/or prospects.

Our California Utilities are also affected by the activities of organizations such as The Utility Reform Network (TURN), Utility Consumers’ Action Network (UCAN), Sierra Club and other stakeholder and advocacy groups. Operations that may be influenced by these groups include

§	the rates charged to our customers;

§	our ability to site and construct new facilities;

§	our ability to purchase or construct generating facilities;

safety;

§	the issuance of securities;

§	accounting matters;

§	transactions between affiliates;

§	the installation of environmental emission controls equipment;

§	our ability to decommission generating facilities and recover the remaining carrying value of such facilities and related costs;

§	our ability to recover costs incurred in connection with nuclear decommissioning activities from trust funds established to pay for such costs;

§	the amount of certain sources of energy we must use, such as renewable sources; limits on the amount of certain energy sources we can use, such as natural gas; and programs to encourage reductions in energy usage by customers; and

§	the amount of costs associated with these operations that may be recovered from customers.

SoCalGas will incur significant costs and expenses to remediate the natural gas leak at its Aliso Canyon natural gas storage facility and to mitigate local community and environmental impacts from the leak, some or a substantial portion of which may not be recoverable through insurance, and SoCalGas also may incur significant liabilities for fines, penalties, damages and greenhouse gas mitigation activities as a result of this incident, some or a significant portion of which may not be recoverable through insurance.

In October 2015, SoCalGas discovered a leak at one of its injection and withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility, located in the northern part of the San Fernando Valley in Los Angeles County. The Aliso Canyon facility, which has been operated by SoCalGas since 1972, is situated in the Santa Susana Mountains. SS25 is more than one mile away from and 1,200 feet above the closest homes. It is one of more than 100 injection and withdrawal wells at the storage facility.

Stopping the Leak and Mitigation Efforts

SoCalGas worked closely with several of the world's leading experts to stop the leak, including planning and obtaining all necessary approvals for drilling relief wells. After discovering the leak, SoCalGas made seven unsuccessful attempts to plug SS25 by pumping fluids down the well shaft. In early December 2015, SoCalGas began drilling a relief well designed to stop the leak by plugging the well at its base. On February 11, 2016, SoCalGas began pumping heavy fluids through the relief well into SS25 near the base of the well, which controlled the flow of natural gas through the well and stopped the leak. In order to permanently seal the well and consistent with directives from the DOGGR and CPUC, SoCalGas then injected cement into SS25 at its base and on February 18, 2016, the DOGGR confirmed that the well was permanently sealed.

Pursuant to a stipulation and order and in response to claims made pursuant to lawsuits described below, SoCalGas has been providing temporary relocation support to residents in the nearby community who request it. In addition, SoCalGas has been providing air filtration and purification systems to those residents in the nearby community requesting them. As a result of receiving the confirmation from DOGGR that the SS25 well was permanently sealed, SoCalGas started winding down its temporary relocation support. Subject to certain exceptions, the period for temporary relocation support to residents who temporarily relocated to short-term housing, such as hotels, concluded on February 25, 2016. This deadline has been challenged and is subject to a recent court order extending such period for an additional 22 days for certain residents. SoCalGas has appealed this order extending the support period. Additionally, residents who have been placed in rental housing will have through the agreed term of their leases to return home. In addition, SoCalGas also intends to mitigate the GHG emissions from the actual natural gas released.

The total costs incurred to remediate and stop the leak and to mitigate environmental and local community impacts will be significant, and to the extent not covered by insurance, or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Governmental Investigations and Civil and Criminal Litigation

Various governmental agencies, including the DOGGR, Los Angeles County Department of Public Health, SCAQMD, CARB, CPUC, EPA, Los Angeles District Attorney’s Office, and California Attorney General’s Office, are investigating this incident. SoCalGas has been working in close cooperation with these agencies.

As of February 24, 2016, 83 lawsuits have been filed against SoCalGas, some of which have also named Sempra Energy, and, in derivative claims on behalf of Sempra Energy and SoCalGas, certain officers and directors of Sempra Energy and SoCalGas. These various lawsuits assert causes of action for negligence, strict liability, property damage, fraud, nuisance, trespass, and breach of fiduciary duties, among other things, and additional litigation may be filed against us in the future related to this incident. Many of these complaints seek class action status, compensatory and punitive damages, injunctive relief, and attorneys’ fees. The Los Angeles City Attorney and Los Angeles County Counsel have also filed a complaint on behalf of the people of the State of California against SoCalGas for public nuisance and violation of the California Unfair Competition Law. The California Attorney General, acting in her independent capacity and on behalf of the people of the State of California and the CARB, joined this lawsuit. The complaint, as amended to include the California Attorney General, adds allegations of violations of California Health and Safety Code sections 41700, prohibiting discharge of air contaminants that cause annoyance to the public, and 25510, requiring reporting of the release of hazardous material, as well as California Government Code section 12607 for equitable relief for the protection of natural resources. The complaint seeks an order for injunctive relief, to abate the public nuisance, and to impose civil penalties. The SCAQMD also filed a complaint against SoCalGas seeking civil penalties for alleged violations of several nuisance-related statutory provisions arising from the leak and delays in stopping the leak. That suit seeks up to $250,000 in civil penalties for each day the violations occurred.

On February 2, 2016, the Los Angeles District Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties for alleged failure to provide timely notice of the leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a), and for violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public.

The costs of defending against these civil and criminal lawsuits and cooperating with these investigations, and any damages and civil and criminal fines and other penalties, if awarded or imposed, could be significant and to the extent not covered by insurance, or if there were to be significant delays in receiving insurance recoveries, could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Governmental Orders, Additional Regulation and Reliability

On January 6, 2016, the Governor of the State of California issued an order (the Governor’s Order) proclaiming a state of emergency to exist in Los Angeles County due to the natural gas leak at the Aliso Canyon facility. The Governor’s Order implements various orders with respect to:

§	stopping the leak;

§	protecting public health and safety;

§	ensuring accountability; and

§	strengthening oversight.

We provide further detail regarding the Governor’s Order in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

On January 23, 2016, the Hearing Board of the SCAQMD ordered SoCalGas to, among other things, stop the leak, control the release of natural gas into the air, and conduct air monitoring and public health studies. We provide further detail regarding the SCAQMD’s order in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

On January 25, 2016, the DOGGR and CPUC selected Blade Energy Partners to conduct an independent analysis under their supervision and to be funded by SoCalGas to investigate the technical root cause of the Aliso Canyon leak. In addition, effective February 5, 2016, the DOGGR amended the California Code of Regulations to require all underground natural gas storage facility operators, including SoCalGas, to take further steps to help ensure the safety of their gas storage operations. Additional hearings in the state legislature as well as with various other regulatory agencies have been or are expected to be scheduled, additional legislation has been proposed in the state legislature, and additional laws, orders, rules and regulations may be adopted.

The costs to comply with the various laws, orders, rules and regulations arising out of this incident could be significant, and to the extent not covered by insurance or in customer rates, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Natural gas withdrawn from storage is important for ensuring service reliability during peak demand periods, including heating needs in the winter, as well as peak electric generation needs in the summer. Aliso Canyon, with a storage capacity of 86 Bcf, is the largest storage facility and an important element of SoCalGas’ delivery system, serving millions of homes and businesses across Southern California. Aliso Canyon represents 63 percent of SoCalGas’ owned natural gas storage capacity. SoCalGas has not injected natural gas into Aliso Canyon since October 25, 2015, and in accordance with the Governor’s Order and subject to contrary CPUC reliability-based direction, SoCalGas will continue this moratorium on further injections until the completion of a review, utilizing independent experts, of the safety of each of the storage wells and air quality in the surrounding communities and an evaluation by an independent panel of scientific and medical experts on whether additional measures are needed to protect public health. We are also currently reviewing the recently released DOGGR safety review requirements associated with returning Aliso Canyon to an active injection/withdrawal status. If this facility were to be taken out of service for any meaningful period of time, it could result in an impairment of the Aliso Canyon facility and significantly higher than expected operating costs and/or additional capital expenditures and natural gas reliability and electric generation could be jeopardized. At December 31, 2015, the Aliso Canyon facility has a net book value of $243 million, excluding $162 million of construction work in progress for the project to construct a new compression station. Any significant impairment of this asset could have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations for the period in which it is recorded. Higher operating costs and additional capital expenditures incurred by SoCalGas may not be recoverable in customer rates, which may have a material adverse effect on our results of operations, cash flows and financial condition.

Insurance

We have at least four kinds of insurance policies that provide in excess of $1 billion in insurance coverage. We have been communicating with our insurance carriers and intend to pursue the full extent of our insurance coverage. These policies are subject to various policy limits, exclusions and conditions. There can be no assurance that we will be successful in obtaining insurance coverage for costs related to the leak under the applicable policies, and to the extent we are not successful, it could result in a material charge against earnings.

We discuss this matter further in Note 15 of the Notes to Consolidated Financial Statements and in “Capital Resources and Liquidity” and “Factors Influencing Future Performance” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

Natural gas pipeline safety assessments may not be fully or adequately recovered in rates.

Pending the outcome of various regulatory agency evaluations of natural gas pipeline safety regulations, practices and procedures, Sempra Energy, including the California Utilities, may incur substantial incremental expense and capital investment associated with their natural gas pipeline operations and investments. The California Utilities filed a comprehensive plan with the CPUC to test or replace natural gas transmission pipelines that either have not been pressure tested or lack sufficient documentation of a pressure test, to enhance existing valve infrastructure and to retrofit pipelines to allow for the use of in-line inspection technology, referred to as SoCalGas’ and SDG&E’s Pipeline Safety Enhancement Plan (PSEP). The California Utilities’ total estimated cost for Phase I (the 10-year period from 2012 to 2022) of the two-phase PSEP was $2.1 billion ($1.6 billion for SoCalGas and $500 million for SDG&E). These cost estimates may continue to change over time to reflect the development of more detailed estimates, actual costs experienced as portions of the work are completed, and changes in scope.

In June 2014, the CPUC issued a final decision approving the utilities’ model for implementing PSEP, and established the criteria to determine the amounts related to PSEP that may be recovered from ratepayers and the processes for recovery of such amounts, including providing that such costs are subject to a reasonableness review. In October 2014, the California Utilities filed a petition for modification with the CPUC requesting authority to recover PSEP costs from customers, subject to refund pending the results of a reasonableness review by the CPUC. The request is pending at the CPUC.

The California Utilities filed an application to recover a portion of PSEP costs that they incurred prior to the CPUC’s June 2014 decision. Certain consumer advocacy groups recommended that the CPUC disallow a portion of these costs, and a CPUC decision in the proceeding remains pending. In the future, consumer advocacy groups may similarly recommend disallowances with respect to applications to recover PSEP costs.

In December 2015, in response to a request by intervenors for rehearing of the June 2014 PSEP decision, the CPUC adopted a decision finding shareholders responsible for the costs associated with pressure testing or replacing transmission pipelines installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. The CPUC previously determined that because no pressure testing requirements existed prior to 1961, SoCalGas and SDG&E could recover the reasonable cost of pressure testing pipelines installed during that timeframe. SoCalGas and SDG&E filed an Application for Rehearing of the December 2015 PSEP decision in January 2016. The December 2015 decision also transfers consideration of SoCalGas’ and SDG&E’s pending petition for modification of the June 2014 PSEP decision, and any other interim rate recovery issues, to a pending PSEP Phase 2 application proceeding. In the Phase 2 PSEP proceeding, SoCalGas and SDG&E seek authority to proceed with initial planning and engineering work in order to develop detailed cost estimates for Phase 2 of PSEP.

If the CPUC were to decide as part of any future reasonableness review or rehearing application that rate recovery not be allowed for PSEP and other gas pipeline safety costs incurred by SoCalGas and SDG&E, it could materially adversely affect the respective company's cash flows, financial condition, results of operations and prospects.

We provide additional information in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

The California Utilities are subject to increasingly stringent safety standards and the potential for significant penalties if regulators deem either SDG&E or SoCalGas to be out of compliance.

In December 2011, the CPUC adopted a natural gas safety citation program whereby natural gas distribution companies can be cited by CPUC staff for violations of the CPUC’s safety standards. In September 2013, the CPUC’s Safety and Enforcement Division issued Standard Operating Procedures setting forth its principles and management process for the natural gas safety citation program.

In 2013, the California State Senate passed legislation Senate Bill (SB) 291 requiring the CPUC to develop and maintain a safety enforcement program that includes procedures for monitoring, data tracking and analysis, and investigations, as well as delegates citation authority to CPUC staff personnel under the direction of the CPUC Executive Director. This legislation required the CPUC to implement the enforcement program for natural gas safety by July 1, 2014 and for electric safety by January 1, 2015. In exercising this citation authority, the CPUC staff is to take into account voluntary reporting of potential violations, voluntary resolution efforts undertaken, prior history of violations, the gravity of the violation, and the degree of culpability.

In December 2014, the CPUC adopted an electric safety enforcement program whereby electric utilities may be cited by CPUC staff for violations of the CPUC’s safety requirements or applicable federal standards.

Under the CPUC’s gas and electric enforcement program, each day of an ongoing violation may be counted as an additional offense. The maximum penalty is $50,000 per offense. Citations under either program may be appealed to the CPUC. Penalties imposed under these programs can be significant, exceeding $1.5 billion in one instance. The CPUC is currently considering proposed refinements to the electric and gas safety enforcement programs, and a decision on these proposals remains pending.

As a result of the natural gas leak at the Aliso Canyon facility, the SCAQMD filed a complaint against SoCalGas seeking civil penalties for alleged violations of several nuisance-related statutory provisions arising from the leak and delays in stopping the leak. The suit seeks up to $250,000 in civil penalties for each day the violations occurred.

If the CPUC or its staff determine that either of SDG&E’s or SoCalGas’ operations and practices are not in compliance with applicable safety standards and operating procedures, the corrective actions required to be in conformance and any penalties imposed could materially adversely affect that company’s cash flows, financial condition, results of operations and prospects.

Meaningful net energy metering, or NEM, reform is necessary to ensure that SDG&E is authorized to recover its costs in providing services to NEM customers while minimizing the cost shift (or subsidy) being borne by non-solar customers.

Due to current rate structures and state policies, customers who self-generate their own power using eligible renewable resources (primarily solar installations) currently do not pay their proportionate cost of maintaining and operating the electric transmission and distribution system, subject to certain limitations, while they still receive power from the system when their self-generation is inadequate to meet their electricity needs. The proportionate costs not paid by NEM customers are paid (i.e., subsidized) by consumers not participating in NEM. In addition, the continuing increase of self-generated solar, other forms of self-generation and other local off-the-grid sources of power adversely impacts the reliability of the electric transmission and distribution system.

In July 2014, the CPUC initiated a rulemaking proceeding to develop a successor tariff to the state’s existing NEM program pursuant to the provisions of AB 327, which required the CPUC to establish a revised NEM tariff or similar program by December 31, 2015. The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable generation. It was originally established in California in 1995 with the adoption of SB 656, as codified in Section 2827 of the Public Utilities Code. Currently, customers who install and operate eligible renewable generation facilities of one megawatt or less may choose to participate in the NEM program. Under NEM, customer-generators receive a full retail rate for the energy they generate that is fed back to the utility’s power grid. This occurs during times when the customer’s generation exceeds their own energy usage. In addition, if a NEM customer generates any electricity over the annual measurement period that exceeds its annual consumption, they receive compensation at a rate equal to a wholesale energy price.

In August 2015, SDG&E proposed a successor NEM tariff that is intended to ensure that all NEM customers pay for the grid and other services they receive, supports the continued growth and adoption of distributed energy resources and helps California meet its energy policy goals. In January 2016, SDG&E, PG&E and Edison filed a joint recommendation to continue the pursuit of a fair and equitable rate structure for all customers. Subsequently in January 2016, the CPUC adopted a final decision in the case that makes modest changes now to require NEM customers to pay some costs that would otherwise be borne by non-NEM customers and moves new NEM customers to time-of-use rates. Together with tiered rate compression discussed under rate reform, the NEM successor tariff begins a process of reducing the cost burden on non-NEM customers. The decision also targets the inclusion of fixed charges for NEM customers beginning in 2019, which is expected to expand the proportion of costs shared by NEM customers.

Appropriate NEM reform is necessary to ensure that SDG&E is authorized to recover, from NEM customers, the costs incurred in providing grid and energy services, as well as mandated legislative and regulatory public policy programs. SDG&E believes this design would be preferable to recovering these costs from customers not participating in NEM. If NEM self-generating installations were to increase substantially between 2016 and 2019 when more significant reforms are to take effect, the rate structure adopted by the CPUC could have a material adverse effect on SDG&E’s business, cash flows, financial condition, results of operations and/or prospects.

The failure by the CPUC to continue reforms of SDG&E’s rate structure, including the implementation of a more significant fixed charge, could have a material adverse effect on its business, cash flows, financial condition, results of operations and/or prospects.

The current electric rate structure in California is primarily based on consumption volume, which places an undue burden on residential customers with higher electric use while subsidizing lower use customers. As higher electric use residential customers switch to self-generation or obtain local off-the-grid sources of power, such as wind, the burden on the remaining higher electric use customers increases, which in turn encourages more self-generation, further increasing rate pressure on existing customers. In July 2015, the CPUC adopted a proposed decision that establishes comprehensive reform and a framework for rates that are more transparent, fair and sustainable. The adopted decision provides for a minimum monthly bill, fewer rate tiers and a gradual reduction in the differences between the tiered rates, directs the utilities to pursue expanded time of use rates, and implements a super-user electric surcharge in 2017 for usage that exceeds average customer usage by approximately 400 percent within each climate zone. The surcharge will increase over time, ultimately reaching a rate of more than double the first tier rate. The adopted decision will be implemented over a five year period from 2015 to 2020, and should result in significant relief for higher-use customers that do not exceed the super-user threshold and a rate structure that better aligns rates with actual costs to serve customers. The adopted decision also establishes a process for implementing a fixed charge in 2020, after the initial reforms are implemented. The establishment of a fixed charge may become more critical to help ensure rates are fair for all customers as distributed energy resources could generally reduce delivered volumes and increase fixed costs.

If the CPUC fails to continue to reform SDG&E’s rate structure by implementing a rate structure that maintains reasonable, cost-based electric rates that are competitive with alternative sources of power and adequate to maintain the reliability of the electric transmission and distribution system, such failure could have a material adverse effect on SDG&E’s business, cash flows, financial condition, results of operations and/or prospects.

Recovery of 2007 wildfire litigation costs requires future regulatory approval.

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. Through December 31, 2015, SDG&E’s payments for claims settlements plus funds estimated to be required for settlement of outstanding claims and legal fees have exceeded its liability insurance coverage and amounts 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. At December 31, 2015, Sempra Energy’s and SDG&E’s Consolidated Balance Sheets included assets of $362 million in Other Regulatory Assets (long-term), of which $359 million is related to CPUC-regulated operations and $3 million is related to FERC-regulated operations, for costs incurred and the estimated resolution of pending claims.

In December 2012, the CPUC issued a final decision allowing SDG&E to maintain an 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. In September 2015, SDG&E filed an application with the CPUC requesting rate recovery of an estimated $379 million of such costs. SDG&E requested a CPUC decision by the end of 2016 and is proposing to recover the costs in rates over a six- to ten-year period. Intervening parties have recommended a phased approach, with Phase 1 addressing the reasonableness of SDG&E’s actions leading up to the fires and a CPUC decision in the second half of 2017. Phase 2 would address the reasonableness of settlements entered into by SDG&E, with a CPUC decision in the second half of 2018. Several parties have protested the application on the basis that SDG&E should be denied cost recovery. Recovery of these costs in rates will require regulatory approvals. 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, at December 31, 2015, the resulting after-tax charge against earnings would have been up to approximately $213 million.

A failure to obtain substantial or full recovery of these costs from customers, 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. In addition, if recovery is permitted, the collection process will extend over a number of years. 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 that is being decommissioned.

SDG&E has a 20-percent ownership interest in SONGS, a 2,150-MW nuclear generating facility near San Clemente, California, that is in the process of being decommissioned by Edison, the majority owner of SONGS. SONGS is subject to the jurisdiction of the NRC and the CPUC. On June 6, 2013, Edison notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the NRC to start the decommissioning activities for the entire facility. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property, and each owner is responsible for financing its share of expenses and capital expenditures, including decommissioning activities. Although the facility is being decommissioned, SDG&E’s ownership interest in SONGS continues to subject it to the risks of owning a partial interest in a nuclear generation facility, 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 prior 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 operations and the decommissioning of the facility; and

§	uncertainties with respect to the technological and financial aspects of decommissioning the facility.

In addition, SDG&E maintains nuclear decommissioning trusts for the purpose of providing funds to decommission SONGS. Trust assets have been generally invested in equity and debt securities, which are subject to significant market fluctuations. A decline in the market value of trust assets or an adverse change in the law regarding funding requirements for decommissioning trusts could increase the funding requirements for these trusts, which in each case may not be fully recoverable in rates. Furthermore, CPUC approval is required in order to make withdrawals from these trusts. CPUC approvals may lag cash expenditures, and approval for certain expenditures may be denied by the CPUC altogether if the CPUC determines that the expenditures are unreasonable. Finally, decommissioning may be materially more expensive than we currently anticipate and therefore may exceed the amounts in the trust funds. Recovery for those overruns would require CPUC approval, which may not occur.

Interpretations of tax regulations may further delay access to nuclear decommissioning trust funds for reimbursement of spent nuclear fuel storage costs. Depending on how the Internal Revenue Service (IRS) or the Department of Treasury ultimately interpret IRS regulations addressing the taxation of a qualified nuclear decommissioning trust, SDG&E may be restricted from withdrawing amounts from its qualified decommissioning trusts to pay for independent spent fuel storage installations (ISFSI) where Edison and SDG&E are seeking, or plan to seek, recovery of the ISFSI costs in litigation against the DOE. Until the DOE litigation is resolved, SDG&E expects to pay for such ISFSI costs unless and until the IRS or the Department of Treasury issue guidance directed to either Edison or SDG&E or to all taxpayers that provides that such ISFSI costs can be funded by qualified nuclear decommissioning trusts. If Edison and SDG&E are unable to obtain timely reimbursement of such costs, such failure could delay decommissioning activities and negatively impact SDG&E's cash flows.

In November 2014, the CPUC approved the Amended Settlement Agreement that resolved the investigation into the steam-generator replacement project that ultimately led to the shut-down of SONGS. Petitions have been filed to reopen the settlement, as we discuss in Note 13 of the Notes to the Consolidated Financial Statements in the Annual Report.

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.

A proposal has been made regarding certain intra-rate case income tax benefits that, if adopted by the CPUC, could have a material adverse effect on SDG&E’s, SoCalGas’ and Sempra Energy’s business, cash flows, financial condition, results of operations, and/or prospects.

As we discuss in Note 14 of the Notes to the Consolidated Financial Statements in the Annual Report, in September 2015, the California Utilities filed settlement agreements with the CPUC that resolve all material matters related to the 2016 General Rate Case proceeding, except for the revenue requirement implications of certain income tax benefits associated with flow-through repair allowance tax deductions. The settlement agreements exclude a proposal for both SDG&E and SoCalGas regarding certain intra-rate case income tax benefits. The proposal recommends that the CPUC adjust SoCalGas’ rate base by $92 million and SDG&E’s rate base by $93 million, and additionally reduce both utilities’ revenue requirements by amounts currently being tracked in income tax memorandum accounts for the year 2015. We believe the proposed treatment would violate and contradict long standing rate making and income tax policy, and would represent a material departure from historical practice. At December 31, 2015, the pretax balances tracked in these memorandum accounts total $74 million for SoCalGas and $39 million for SDG&E. If this proposal is adopted, the outcome would reduce the revenue requirement amounts agreed to in SDG&E’s and SoCalGas’ settlement agreements. SDG&E and SoCalGas do not expect that the prospective reduction to rate base described above would result in an immediate earnings impact if this proposal is adopted. However, if this proposal is adopted, the amounts currently being tracked in the tax memorandum accounts for 2015 could result in a material charge against earnings when the draft decision is received.

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. Energy-related commodity prices impact LNG liquefaction and regasification, the transport and storage of natural gas, and power generation from renewable and conventional sources, among other businesses that we operate and invest in.

We buy energy-related commodities from time to time, for LNG terminals or power plants 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 natural gas, LNG, electricity 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 and natural gas producing nations or organizations affecting the global supply of crude oil and natural gas

§	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, they 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, providing for direct pass-through of operating costs 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 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, transmission and distribution 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 (EPC) agreements

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

§	timely receipt of required governmental permits, licenses, authorizations, and rights of way and maintenance or extension of these authorizations

§	timely implementation and satisfactory completion of construction

§	obtaining adequate and reasonably priced financing for the project

Successful completion of a particular project may be materially adversely affected by, among other factors:

§	unforeseen engineering problems

§	construction delays and contractor performance shortfalls

§	work stoppages

§	failure to obtain, maintain or extend required governmental permits, licenses, authorizations, and rights of way

§	equipment unavailability or delay and cost increases

§	adverse weather conditions

§	environmental and geological conditions

§	litigation

§	unsettled property rights

If we are unable to complete a development project 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 electric generation, transmission and distribution facilities, or natural gas regasification, liquefaction 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, liquefaction, storage, transmission and distribution 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.

The design, development and construction of the Cameron LNG liquefaction facility involves numerous risks and uncertainties.

With respect to our project to add LNG export capability at the Cameron LNG facility, the Cameron LNG Holdings, LLC joint venture (Cameron LNG JV) has begun building an LNG export facility consisting of three liquefaction trains designed to a total nameplate capacity of 13.9 million tonnes per annum (Mtpa) of LNG with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. The anticipated incremental investment in the three-train liquefaction project is estimated to be approximately $7 billion, including the cost of the lump-sum, turnkey construction contract, development engineering costs and permitting costs, but excluding capitalized interest and other financing costs. The total cost of the facility, including the cost of our original regasification facility contributed to the joint venture plus interest during construction, financing costs and required reserves, is estimated to be approximately $10 billion. The majority of the incremental investment in the joint venture will be project-financed and the balance provided by the project partners. Any failure by the project partners to make their required investments on a timely basis could result in project delays and could materially adversely affect the development of the project. In addition, Sempra Energy has entered into completion guarantees under which it has guaranteed a maximum $3.7 billion of principal amount of the project financing for the project. These guarantees terminate upon Cameron LNG JV’s achieving “financial completion” of the initial three-train liquefaction project, including all three trains achieving commercial operation and meeting certain operational performance tests. If, due to the joint venture’s failure to satisfy the financial completion criteria, we are required to repay some or all of the $3.7 billion principal amount of project debt under our completion guarantees, any such repayments could have a material adverse effect on our business, results of operations, cash flows, financial condition, and/or prospects.

Large-scale construction projects like the design, development and construction of the Cameron LNG liquefaction facility involve numerous risks and uncertainties, including among others, the potential for unforeseen engineering problems, substantial construction delays and increased costs. Cameron LNG JV has a turnkey EPC contract with a joint venture contractor comprised of subsidiaries of Chicago Bridge & Iron Company N.V. and Chiyoda Corporation, who are jointly and severally liable for performance under the contract. If the contractor becomes unwilling or unable to perform according to the terms and timetable of the EPC contract, Cameron LNG JV would be required to engage a substitute contractor, which would result in project delays and increased costs, which could be significant. The construction of this facility requires a large and specialized work force, necessary equipment and materials, and sophisticated engineering. There can be no assurance that Cameron LNG JV’s contractor will not encounter delays due to disruptions in obtaining the necessary equipment and materials, inability to field the necessary workforce, or engineering issues that were not contemplated. As construction progresses, Cameron LNG JV may decide or be forced to submit change orders to the contractor that could result in longer construction periods and higher construction costs or both. In addition, weather conditions, new regulation, labor disputes, breakdown or failure of equipment, and litigation, such as the lawsuit filed by the Sierra Club and Gulf Restoration Network challenging the June 19, 2014 FERC order that approved the construction of the Cameron LNG liquefaction project, could substantially delay the project. As we do not control Cameron LNG JV, we are dependent on reaching a consensus with one or more of our joint venture partners to resolve a variety of issues that could transpire. The inability to timely resolve issues, including construction issues, could cause substantial delays to the completion of this project. A substantial delay could result in cost overruns, substantially postpone the earnings we anticipate deriving from this facility, and require additional cash investments by us and our joint venture partners. 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 approximately $7 billion of incremental investment, excluding capitalized interest and other financing costs. These risks could have a material adverse effect on our business, results of operations, cash flows, financial condition, and/or prospects.

We face many challenges to develop and complete our contemplated LNG export facilities.

In addition to the three-train Cameron LNG liquefaction facility described above, we are looking at several other LNG export terminal development opportunities, including a greenfield project in Port Arthur, Texas, a brownfield project at our existing Energía Costa Azul regasification facility in Baja California, Mexico and an expansion of up to two additional liquefaction trains to the Cameron liquefaction facility. Each of these contemplated projects faces numerous risks and must overcome significant hurdles before we can proceed with construction. Common to all of these projects is the risk that an extended decline in current and forward projections of crude oil prices could reduce the demand for natural gas in some sectors and cause a corresponding reduction in projected global demand for LNG. This could result in increased competition among those working on projects in an environment of declining LNG demand, such as the Sempra Energy-sponsored export initiatives. Such reduction in natural gas demand could also occur from higher penetration of coal in new power generation, which could also lead to increased competition among the LNG suppliers for the declining LNG demand. Oil prices at certain moderate levels could also make LNG projects in other parts of the world still feasible and competitive with LNG projects from North America, thus increasing supply and the competition for the available LNG demand. A decline in natural gas prices outside the United States (which in many foreign countries are based on the price of crude oil) may also materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing).

Sempra Natural Gas has entered into a project development agreement for the joint development of the proposed Port Arthur liquefaction project with an affiliate of Woodside Petroleum Ltd. The agreement specifies how the parties will share costs, and establishes a framework for the parties to work jointly on permitting, design, engineering, and commercial and marketing activities associated with developing the Port Arthur liquefaction project. Also, Sempra Natural Gas, IEnova and a subsidiary of PEMEX entered into a memorandum of understanding to collaborate in and share the costs of the potential development of a liquefaction project at IEnova’s Energía Costa Azul facility in Mexico. Any decisions by the parties to proceed with binding agreements with respect to the formation of these potential joint ventures and the potential development of these projects will require, among other things, completion of project assessments and achieving other necessary internal and external approvals of each such party. In addition, all of our proposed projects are subject to a number of risks and uncertainties, including the receipt of a number of permits and approvals; finding suitable partners and customers; obtaining financing; negotiating and completing suitable commercial agreements, including joint venture agreements, tolling capacity agreements or natural gas supply and LNG sales agreements and construction contracts; and reaching a final investment decision.

Expansion of the Cameron LNG liquefaction facility beyond the first three trains is subject to certain restrictions and conditions under the joint venture project financing agreements, including among others, timing restrictions on expansion of the project unless appropriate prior consent is obtained from the project lenders. Furthermore, there are a number of potential new projects under construction or in the process of development by various project developers in North America, in addition to ours, and given the projected global demand for LNG, the vast majority of these projects likely will not be completed. With respect to our Port Arthur, Texas project, this is a greenfield site, and therefore it may not have the advantages often associated with brownfield sites. The Energía Costa Azul facility in Mexico is subject to on-going land and permitting disputes that could make project financing difficult as well as finding suitable partners and customers. In addition, while we have completed the regulatory process for an LNG export facility in the U.S., the regulatory process in Mexico and the overlay of U.S. regulations for natural gas exports to an LNG export facility in Mexico are not well developed. There can be no assurance that such a facility could be permitted and constructed without facing significant legal challenges and uncertainties, which in turn could make project financing, as well as finding suitable partners and customers, difficult. Finally, Energía Costa Azul has profitable long-term regasification contracts for 100 percent of the facility, making the decision to pursue a new liquefaction facility dependent in part on whether the investment in a new liquefaction facility would, over the long term, be more beneficial than continuing to supply regasification services under our existing contracts.

There can be no assurance that our contemplated LNG export facilities will be completed, and our inability to complete one or more of our contemplated LNG export facilities could have a material adverse effect on our future cash flows, results of operations and prospects.

We discuss these projects further in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance” in the Annual Report.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could reduce or eliminate LNG export opportunities and demand.

Several states have adopted or are considering adopting regulations to impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict the performance of or prohibit the well drilling in general and/or hydraulic fracturing in particular. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies have asserted regulatory authority over certain hydraulic fracturing activities. For example, the EPA issued permitting guidance in February 2014 under the federal Safe Drinking Water Act (SDWA) for hydraulic fracturing activities involving the use of diesel fuels. In April 2015, the EPA issued a proposed rule that would prevent the discharge of hydraulic fracturing wastewater into publicly owned treatment works, and in March 2015, the Bureau of Land Management of the U.S. Department of the Interior adopted rules imposing new requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure of hydraulic fracturing chemicals, as well as wellbore integrity and handling of flowback water. In addition, the U.S. Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. There are also certain governmental reviews that have been conducted or are underway on deep shale and other formation completion and production practices, including hydraulic fracturing. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate or even ban such activities. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process.

We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, natural gas prices in North America could rise, which in turn could materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing). Increased regulation or difficulty in permitting of hydraulic fracturing, and any corresponding increase in domestic natural gas prices, could materially adversely affect demand for LNG exports and our ability to develop commercially viable LNG export facilities beyond the three train Cameron LNG facility currently under construction.

Increased competition could materially adversely affect us.

The markets in which we operate are characterized by numerous strong and capable competitors, many of whom may have extensive and diversified developmental and/or operating experience (including both domestic and international) and financial resources similar to or greater than ours. Further, in recent years, the natural gas pipeline, storage and LNG market segments have been characterized by strong and increasing competition both with respect to winning new development projects and acquiring existing assets. In Mexico, despite the commissioning of many new energy infrastructure projects by the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE) and other governmental agencies in connection with energy reforms, competition for recent pipeline projects has been intense with numerous bidders competing aggressively for these projects. There can be no assurance that we will be successful in bidding for new development opportunities in the U.S., Mexico or South America. In addition, as noted above, there are a number of potential new LNG liquefaction projects under construction or in the process of being developed by various project developers in North America, including our contemplated new projects, and given the projected global demand for LNG, the vast majority of these projects likely will not be completed. Finally, our natural gas storage assets in the Gulf Coast region compete with other facilities for storage customers as existing contracts expire and for anchor customers that could support development of new capacity. These competitive factors could have a material adverse effect on our business, results of operations, cash flows and/or prospects.

We may elect not to, or may not be able to, enter into, extend or replace expiring 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. Such long-term contracts, once entered into, increase our credit risk if our counterparties fail to perform or become unable to meet their contractual obligations on a timely basis due to bankruptcy, insolvency, or otherwise.

The Energía Costa Azul LNG facility and the Cameron LNG facility (within the Cameron LNG JV) have entered into long-term capacity agreements with a limited number of counterparties at each facility. Under these agreements, customers pay capacity reservation and usage fees to receive, store and regasify the customers’ LNG. We also may enter into short-term and/or long-term supply agreements to purchase LNG to be received, stored and regasified 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. 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.

At Cameron LNG JV, although the Cameron LNG terminal is partially contracted for regasification, there is a termination agreement in place that will result in the termination of this agreement at the point in the construction of the new liquefaction facilities where piping tie-ins to the existing regasification terminal become necessary, which we expect to occur during the first quarter of 2017.

Sempra Mexico’s and Sempra Natural Gas’ ability to enter into or replace existing long-term firm capacity agreements for their 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. A significant sustained decrease in demand for and supply of LNG and/or natural gas from such customers could have a material adverse effect on our businesses, results of operations, cash flows and/or prospects.

Sempra Natural Gas owns a 25-percent interest in Rockies Express Pipeline LLC (Rockies Express), a partnership that operates a natural gas pipeline, the Rockies Express pipeline (REX). All of Rockies Express’ original capacity sales on REX provided for west-to-east service. Sempra Natural Gas has an agreement for such capacity on REX through November 2019. The capacity costs are offset by revenues from releases of the capacity contracted to third parties. Certain capacity release commitments totaling $22 million concluded during 2013. Contracting activity related to that capacity has not been sufficient to offset all of our capacity payments to Rockies Express. Rockies Express has been developing east-to-west service offerings on REX. In 2013, FERC issued a decision ruling that east-to-west service offerings within a single REX zone would not result in potential rate reductions under “most favored nation” provisions in the original customers’ west-to-east contracts, and certain west-to-east customers sought rehearing of that decision. In 2014 and 2015, Rockies Express reached settlements with these west-to-east customers, and the customers’ requests for rehearing have been withdrawn. In addition, several customers are facing liquidity issues which may result in bankruptcy. There can be no assurance that if those customers enter bankruptcy, that we will be able to find new customers to replace that capacity.

Our natural gas storage assets include operational and development assets at Bay Gas Storage Company, Ltd. (Bay Gas) in Alabama and Mississippi Hub, LLC (Mississippi Hub) in Mississippi, as well as our development project, LA Storage, LLC (LA Storage) in Louisiana. LA Storage could be positioned to support LNG export from the Cameron LNG JV terminal and other liquefaction projects, if anticipated cash flows support further investment. However, changes in the U.S. natural gas market could also lead to diminished natural gas storage values. Historically, the value of natural gas storage services has positively correlated with the difference between the seasonal prices of natural gas, among other factors. In general, over the past several years, seasonal differences in natural gas prices have declined, which have contributed to lower prices for storage services. As our legacy (higher rate) sales contracts mature at our Bay Gas and Mississippi Hub facilities, replacement sales contract rates have been and could continue to be lower than has historically been the case. Lower sales revenues may not be offset by cost reductions, which could lead to depressed asset values. In addition, our LA Storage development project may be unable to either attract cash flow commitments sufficient to support further investment or extend its FERC construction permit beyond its current expiration date of June 2017. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage Pipeline, that is not contracted. Market conditions could result in the need to perform recovery testing of our recorded asset values. In the event such values are not recoverable, we would consider the fair value of these assets relative to their recorded value. To the extent the recorded (carrying) value is in excess of the fair value, we would record a noncash impairment charge. The recorded value of our long-lived natural gas storage assets at December 31, 2015 was $1.5 billion. A significant impairment charge related to our natural gas storage assets would have a material adverse effect on our results of operations in the period in which it is recorded.

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, and we may be unable to sell the power that Sempra Renewables’ 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.

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

Our businesses depend on counterparties, business partners, customers, and suppliers performing in accordance with their agreements. If they fail to 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.

Our businesses, and the businesses that we invest in, 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 or arrangements will not perform their obligations in accordance with such agreements or arrangements. Should they fail to perform, we may be required to enter into alternative arrangements or to honor the underlying commitment at then-current market prices. In such an event, we may incur additional losses to the extent of amounts already paid to such counterparties or suppliers. In addition, many such agreements are important for 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.

Our businesses are subject to various legal actions challenging our property rights and permits.

We are engaged in disputes regarding our title to the properties adjacent to and properties where our LNG terminal in Mexico is located, as we discuss in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report. In the event that we are unable to defend and retain title to the properties on which our LNG terminal is located, we could lose our rights to occupy and use such properties and the related terminal, which could result in breaches of one or more permits or contracts that we have entered into with respect to such terminal. In addition, our ability to convert the LNG terminal into an export facility may be hindered by these disputes, and they could make project financing such a facility and finding suitable partners and customers very difficult. If we are unable to occupy and use such properties and the related 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 gas storage and 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 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 electricity, natural gas supplies and LNG 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.

In Mexico, we own or have interests in natural gas, propane and ethane distribution, storage and transportation projects, electricity generation, distribution and transmission facilities, and an LNG terminal. In Peru and Chile, we own or have interests in electricity generation, transmission and distribution facilities and operations. 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, as we discuss below

§	foreign cash balances that may be unavailable to fund U.S. operations, or available only at unfavorable U.S. and/or foreign tax rates upon repatriation of such amounts or changes in tax law

§	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

§	compliance with the Foreign Corrupt Practices Act and similar laws

§	valuation of goodwill

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. We may or may not choose to hedge these risks, and any hedges entered into may or may not be effective. 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 and other international energy projects 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.

Other Risks

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

Sempra Energy makes investments in entities that we do not control or manage or in which we share control. As described above, SDG&E holds a 20-percent ownership interest in SONGS, which is in the process of being decommissioned by Edison, its majority owner. Sempra Natural Gas accounts for its investment in the Cameron LNG JV under the equity method, which investment is $983 million at December 31, 2015. Also, Sempra Natural Gas owns a 25-percent interest in Rockies Express, a joint venture that operates the REX natural gas pipeline. Our investment in Rockies Express was $477 million at December 31, 2015. At December 31, 2015, Sempra Renewables had investments totaling $855 million in several joint ventures to develop and operate renewable generation facilities. Sempra Mexico has a 50-percent interest in a joint venture with PEMEX that operates several natural gas pipelines and propane and ethane systems in northern Mexico. Sempra Mexico also has a 50-percent interest in a renewables wind project in Baja California. At December 31, 2015, these investments totaled $519 million. Sempra Energy has an investment balance of $67 million at December 31, 2015 that reflects remaining distributions expected to be received from the RBS Sempra Commodities LLP (RBS Sempra Commodities) 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. The failure to collect all or a substantial portion of our remaining investment in the RBS Sempra Commodities partnership could have a corresponding impact on our cash flows, financial condition and results of operations.

Sempra Renewables and Sempra Natural Gas have provided guarantees related to joint venture financing agreements, and Sempra South American Utilities and Sempra Mexico have provided loans to joint ventures in which they have investments and to other affiliates. We discuss the guarantees in Note 4, and affiliate loans in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

We have limited influence over these ventures 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. We discuss our investments further in Notes 3, 4 and 10 of the Notes to Consolidated Financial Statements in the Annual Report.

Market performance or changes in other assumptions could require Sempra Energy, SDG&E and/or SoCalGas to make significant unplanned contributions to their pension and other postretirement benefit plans.

Sempra Energy, SDG&E and SoCalGas provide defined benefit pension plans and other postretirement benefits to eligible employees and retirees. A decline in the market value of plan assets may increase the funding requirements for these plans. In addition, the cost of providing pension and other postretirement benefits is also affected by other factors, including the assumed rate of return on plan assets, employee demographics, discount rates used in determining future benefit obligations, rates of increase in health care costs, levels of assumed interest rates and future governmental regulation. An adverse change in any of these factors could cause a material increase in our funding obligations which 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, 2015, SDG&E owns and operates four natural gas-fired power plants:

§	a 565-MW electric generation facility (the Palomar generation facility) in Escondido, California

§	a 480-MW electric generation facility (the Desert Star generation facility) in Boulder City, Nevada

§	a 96-MW electric generation peaking facility (the Miramar Energy Center) in San Diego, California

§	a 45-MW electric generation facility (the Cuyamaca Peak Energy Plant) in El Cajon, California

SDG&E’s interest in SONGS, as well as matters related to SONGS’ retirement and related issues, are described in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

At December 31, 2015, 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 2,079 miles of transmission lines, 23,272 miles of distribution lines and 161 substations. Periodically, various areas of the service territory require expansion to accommodate customer growth.

NATURAL GAS PROPERTIES – CALIFORNIA UTILITIES

At December 31, 2015, SDG&E’s natural gas facilities consisted of two compressor stations, 168 miles of transmission pipelines, 8,600 miles of distribution pipelines and 6,451 miles of service pipelines.

At December 31, 2015, SoCalGas’ natural gas facilities included 2,962 miles of transmission and storage pipelines, 50,097 miles of distribution pipelines and 47,524 miles of service pipelines. They also included 11 transmission compressor stations and four underground natural gas storage reservoirs with a combined working capacity of 137 Bcf. We discuss recent events concerning SoCalGas’ Aliso Canyon natural gas storage facility in “Risk Factors” above and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance” and Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

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

At December 31, 2015, Sempra Mexico and Sempra Renewables operate or own interests in a power plant and/or renewable generation facilities in North America with a total capacity of 2,655 MW. Our share of this capacity is 1,671 MW. We provide additional information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Notes 4 and 18 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra South American Utilities operates Chilquinta Energía, which serves customers in the cities of Valparaiso and Viña del Mar in central Chile. Its property consists of 10,012 miles of distribution lines, 342 miles of transmission lines and 47 substations. Chilquinta Energía and Sociedad Austral de Electricidad Sociedad Anónima (SAESA) are 50-percent partners in Eletrans S.A., an electric transmission company that operates a 100-mile double circuit 220-kV transmission line, which extends from Cardones to Diego de Almagro in Chile.

Sempra South American Utilities operates Luz del Sur, which serves customers in the southern zone of metropolitan Lima, Peru. Its property consists of 13,458 miles of distribution lines, 185 miles of transmission lines and 36 substations. Luz del Sur began commercial operation of Santa Teresa, a 100-MW hydroelectric power plant located in the Cusco region of Peru, in September 2015.

At December 31, 2015, Sempra Mexico’s operations included 2,252 miles of distribution pipelines, 543 miles of transmission pipelines and three compressor stations. Sempra Mexico operates its Energía Costa Azul LNG regasification terminal on land it owns in Baja California, Mexico. Sempra Mexico’s IEnova subsidiary has a 50-percent interest in the joint venture Gasoductos de Chihuahua, which develops and operates energy infrastructure in Mexico. In July 2015, IEnova entered into an agreement to purchase its joint venture partner’s 50-percent interest. We discuss the potential transaction in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report.

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

Sempra Natural Gas and its partner, ProLiance Transportation and Storage, LLC, own three 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, LA Storage.

The Sempra Natural Gas segment 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.

The Sempra Natural Gas segment also owns and operates Willmut Gas, a natural gas distribution utility headquartered 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 20 Bcf natural gas storage facility, Bay Gas, under a land lease, with the potential to expand total working capacity to 26 Bcf. Sempra Natural Gas also owns land in Simpson County, Mississippi, on which it operates a 22 Bcf natural gas storage facility, Mississippi Hub, with the potential to expand total working capacity to 30 Bcf. We will evaluate additional cavern and associated pipeline expansion opportunities at Bay Gas and Mississippi Hub based on regional market demand for storage services.

Sempra Natural Gas owns land in Port Arthur, Texas, for potential development. Sempra Natural Gas also has an equity interest in Cameron LNG JV, which owns land and an LNG regasification terminal and has a land lease in Hackberry, Louisiana. The joint venture is constructing a liquefaction terminal at the facility.

OTHER PROPERTIES

Sempra Energy occupies its 16-story corporate headquarters building in San Diego, California, pursuant to a 25-year, build-to-suit lease that expires in 2040. The lease has five five-year renewal options. We discuss the details of this lease further in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

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, California, pursuant to two separate operating leases, both ending in December 2024. 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 United States, Mexico, Chile and Peru, with the leases ending from 2016 to 2021.

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 13, 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 a long-term incentive plan that permits the grant of a wide variety of equity and equity-based incentive awards to directors, officers and key employees. At December 31, 2015, outstanding awards consisted of stock options, restricted stock, and restricted stock units held by 421 employees.

The following table sets forth information regarding our equity compensation plan at December 31, 2015.

EQUITY COMPENSATION PLAN

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(B)

issuance(C)(D)

Equity compensation plan approved

by shareholders:

2013 Long-Term Incentive Plan

3,148,478

53.62

6,148,009

(A)

Consists of 527,997 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, 2,211,351 performance-based restricted stock units and 409,130 restricted stock units that are service-based or issued in connection with certain other criteria. Each performance-based restricted stock unit represents the right to receive from zero to 1.5 shares (2.0 shares for awards granted during or after 2014) of our common stock if applicable performance conditions are satisfied. The 3,148,478 also includes awards granted under two previously shareholder-approved long-term incentive plans (Predecessor Plans). No new awards may be granted under these Predecessor Plans.

(B)

Represents only the weighted-average exercise price of the 527,997 options to purchase shares of common stock.

(C)

The number of shares available for future issuance is increased by the number of shares or units withheld or surrendered to satisfy the exercise price or to satisfy tax withholding obligations relating to any plan awards.

(D)

The number of shares available for future issuance is increased by the number of shares subject to awards that expire or are forfeited, canceled or otherwise terminated without the issuance of shares.

We provide additional discussion of share-based compensation in Note 8 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 prepaid $500 million to repurchase a total of 9,574,435 shares of our common stock in 2010 and 2011. No shares have been repurchased under this authorization since 2011. 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 long-term incentive 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 85.

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 99 through 249 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

None.

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

Because SDG&E meets the conditions of General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this report with a reduced disclosure format as permitted by General Instruction I(2), the information required by Items 10, 11, 12 and 13 below is not required for SDG&E. We have, however, provided the information required by Item 10 with respect to SDG&E’s executive officers in Part I, Item 1. Business under “Executive Officers of the Registrants – SDG&E and SoCalGas.”

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 2016 annual meeting of shareholders.

SOCALGAS

We provide the information required by Item 10 with respect to executive officers for 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 company’s Information Statement prepared for its May 2016 annual meeting 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 2016 annual meeting of shareholders for Sempra Energy and from the Information Statement prepared for the May 2016 annual meeting of shareholders for 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 2016 annual meeting of shareholders for Sempra Energy and in the Information Statement prepared for the May 2016 annual meeting of shareholders for 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 2016 annual meeting of shareholders for Sempra Energy and from the Information Statement prepared for the May 2016 annual meeting of shareholders for SoCalGas.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information regarding principal accountant fees and services, as required by Item 14, is presented below for Sempra Energy, SDG&E and SoCalGas. The following table shows the fees paid to Deloitte & Touche LLP, the independent registered public accounting firm for Sempra Energy, SDG&E and SoCalGas, for services provided for 2015 and 2014.

PRINCIPAL ACCOUNTANT FEES
(Dollars in thousands)
	Sempra Energy
	Consolidated					SDG&E					SoCalGas
			Percent					Percent					Percent
	Fees		of total			Fees		of total			Fees		of total
2015:
Audit fees:
Consolidated financial statements and
internal controls audits, subsidiary
and statutory audits(1)	$	11,269				$	2,430				$	2,516
Regulatory filings and related services		200					58					59
Total audit fees		11,469		91	%		2,488		89	%		2,575		87	%
Audit-related fees:
Employee benefit plan audits		430					134					218
Other audit-related services,
accounting consultation		229					32					95
Total audit-related fees		659		5			166		6			313		11
Tax planning and compliance fees		440		4			140		5			54		2
All other fees		46		―			8		―			9		―
Total fees	$	12,614		100	%	$	2,802		100	%	$	2,951		100	%
2014:
Audit fees:
Consolidated financial statements and
internal controls audits, subsidiary
and statutory audits	$	9,217				$	2,362				$	2,412
Regulatory filings and related services		187					―					86
Total audit fees		9,404		89	%		2,362		91	%		2,498		89	%
Audit-related fees:
Employee benefit plan audits		430					134					219
Other audit-related services,
accounting consultation		357					34					―
Total audit-related fees		787		7			168		6			219		8
Tax planning and compliance fees		346		3			81		3			84		3
All other fees		53		1			―		―			―		―
Total fees	$	10,590		100	%	$	2,611		100	%	$	2,801		100	%

(1)

Sempra Energy Consolidated includes $1.8 million of audit services relating to a confidential submission of a subsidiary's Form S-1 to the Securities and Exchange Commission for its potential master limited partnership formation and initial public offering.

The Audit Committee of Sempra Energy’s board of directors is directly responsible for the appointment, compensation, retention and oversight of the independent registered public accounting firm for Sempra Energy and its subsidiaries, including SDG&E and SoCalGas. As a matter of good corporate governance, the SDG&E and SoCalGas boards of directors also reviewed the performance of Deloitte & Touche LLP and concurred with the determination by the Sempra Energy Audit Committee to retain them as the independent registered public accounting firm for each of Sempra Energy, SDG&E and SoCalGas. Sempra Energy’s board has determined that each member of its Audit Committee is an independent director and is financially literate, and that Mr. Taylor, the chair of the committee, and Mr. Brocksmith are each an audit committee financial expert as defined by the rules of the SEC.

Except where pre-approval is not required by SEC rules, Sempra Energy’s Audit Committee pre-approves all audit and permissible non-audit services provided by Deloitte & Touche LLP for Sempra Energy and its subsidiaries. The committee’s pre-approval policies and procedures provide for the general pre-approval of specific types of services and give detailed guidance to management as to the services that are eligible for general pre-approval. They require specific pre-approval of all other permitted services. For both types of pre-approval, the committee considers whether the services to be provided are consistent with maintaining the firm’s independence. The policies and procedures also delegate authority to the chair of the committee to address any requests for pre-approval of services between committee meetings, with any pre-approval decisions to be reported to the committee at its next scheduled meeting.

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

Evaluation of Disclosure Controls and Procedures	91	91	91

Management’s Report On Internal Control Over Financial Reporting	91	91	91

Reports of Independent Registered Public Accounting Firm	93	95	97

Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013	99	106	113

Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2015, 2014 and 2013	100	107	114

Consolidated Balance Sheets at December 31, 2015 and 2014	101	108	115

Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013	103	110	117

Consolidated Statements of Changes in Equity for the years ended December 31, 2015, 2014 and 2013	105	112	N/A

Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2015, 2014 and 2013	N/A	N/A	118

Notes to Consolidated Financial Statements	119	119	119
(1) Incorporated by reference from the indicated pages of the 2015 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 55 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 63 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. 333-198572 on Form S-3 and 333-200828, 333-188526, 333-182225, 333-56161, 333-50806, 333-49732, 333-121073, 333-151184, 333-155191, 333-129774 and 333-157567 on Form S-8 of our reports dated February 26, 2016, 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, 2015.

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, 2016

SAN DIEGO GAS & ELECTRIC COMPANY

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

We consent to the incorporation by reference in Registration Statement No. 333-205410 on Form S-3 of our reports dated February 26, 2016, 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, 2015.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2016

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. 333-205950 on Form S-3 of our reports dated February 26, 2016, 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, 2015.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2016

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,
	2015			2014			2013

Interest income	$	―		$	―		$	42
Interest expense		(261	)		(235	)		(239	)
Operation and maintenance		(66	)		(78	)		(63	)
Other income, net		7			50			41
Income tax benefits		150			133			117
Loss before equity in earnings of subsidiaries		(170	)		(130	)		(102	)
Equity in earnings of subsidiaries, net of income taxes		1,519			1,291			1,103
Net income/earnings	$	1,349		$	1,161		$	1,001

Basic earnings per common share	$	5.43		$	4.72		$	4.10
Weighted-average number of shares outstanding (thousands)		248,249			245,891			243,863

Diluted earnings per common share	$	5.37		$	4.63		$	4.01
Weighted-average number of shares outstanding (thousands)		250,923			250,655			249,332
See Notes to Condensed Financial Information of Parent.

SEMPRA ENERGY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31,
	Pretax			Income tax			Net-of-tax
	amount			benefit (expense)			amount
2015:
Net income	$	1,199		$	150		$	1,349
Other comprehensive income (loss):
Foreign currency translation adjustments		(260	)		―			(260	)
Financial instruments		(80	)		33			(47	)
Pension and other postretirement benefits		(3	)		1			(2	)
Total other comprehensive loss		(343	)		34			(309	)
Comprehensive income	$	856		$	184		$	1,040
2014:
Net income	$	1,028		$	133		$	1,161
Other comprehensive income (loss):
Foreign currency translation adjustments		(193	)		―			(193	)
Financial instruments		(106	)		42			(64	)
Pension and other postretirement benefits		(20	)		8			(12	)
Total other comprehensive loss		(319	)		50			(269	)
Comprehensive income	$	709		$	183		$	892
2013:
Net income	$	884		$	117		$	1,001
Other comprehensive income (loss):
Foreign currency translation adjustments		111			―			111
Financial instruments		13			(4	)		9
Pension and other postretirement benefits		47			(19	)		28
Total other comprehensive income		171			(23	)		148
Comprehensive income	$	1,055		$	94		$	1,149
See Notes to Condensed Financial Information of Parent.

SEMPRA ENERGY
CONDENSED BALANCE SHEETS
(Dollars in millions)
		December 31,		December 31,
		2015		2014(1)
Assets:
Cash and cash equivalents		$	4	$	3
Due from affiliates			62		101
Deferred income taxes			―		398
Other current assets			4		15
Total current assets			70		517

Investments in subsidiaries			15,586		14,557
Due from affiliates			457		174
Deferred income taxes			2,188		1,544
Other assets			641		609
Total assets		$	18,942	$	17,401

Liabilities and shareholders’ equity:
Current portion of long-term debt		$	752	$	―
Due to affiliates			332		338
Income taxes payable			42		93
Other current liabilities			310		271
Total current liabilities			1,436		702

Long-term debt			5,195		4,644
Due to affiliates			―		230
Other long-term liabilities			502		499
Shareholders’ equity			11,809		11,326
Total liabilities and shareholders’ equity		$	18,942	$	17,401
(1)	As adjusted for the retrospective adoption of ASU 2015-03.
See Notes to Condensed Financial Information of Parent.

SEMPRA ENERGY
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013

Net cash used in operating activities	$	(255	)	$	(260	)	$	(131	)

Dividends received from subsidiaries		350			300			50
Expenditures for property, plant and equipment		(43	)		(15	)		(1	)
Purchase of trust assets		(5	)		(4	)		(5	)
Proceeds from sales by trust		―			―			10
Capital contribution to subsidiaries		―			―			(6	)
(Increase) decrease in loans to affiliates, net		(457	)		627			962
Cash (used in) provided by investing activities		(155	)		908			1,010

Common stock dividends paid		(628	)		(598	)		(606	)
Issuances of common stock		52			56			62
Repurchases of common stock		(74	)		(38	)		(45	)
Issuances of long-term debt		1,248			499			498
Payments on long-term debt		―			(800	)		(650	)
(Decrease) increase in loans from affiliates, net		(230	)		234			(147	)
Tax benefit related to share-based compensation		52			―			―
Other		(9	)		(4	)		(3	)
Cash provided by (used in) financing activities		411			(651	)		(891	)

Increase (decrease) in cash and cash equivalents		1			(3	)		(12	)
Cash and cash equivalents, January 1		3			6			18
Cash and cash equivalents, December 31	$	4		$	3		$	6

SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
Financing of build-to-suit property	$	61		$	61		$	14
Common dividends issued in stock		55			42			―
Dividends declared but not paid		174			163			154
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 $3 million, $27 million and $39 million of gains on dedicated assets in support of our executive retirement and deferred compensation plans in 2015, 2014 and 2013, respectively.

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

Note 2. New Accounting Standards

Accounting Standards Update (ASU) 2015-03, “Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) and ASU 2015-15, “Interest – Imputation of Interest: Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” (ASU 2015-15): ASU 2015-03 provides guidance on the financial statement presentation of debt issuance costs and requires an entity to present debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related long-term debt liability. This guidance must be applied using a full retrospective approach for all periods presented in the period of adoption. Sempra Energy retrospectively adopted ASU 2015-03 during the annual reporting period ended December 31, 2015, and the adoption did not affect its results of operations or cash flows. The Condensed Balance Sheet at December 31, 2014 reflects the reclassification of $22 million from Other Assets to Long-Term Debt.

ASU 2015-17, “Income Taxes – Balance Sheet Classification of Deferred Taxes” (ASU 2015-17): ASU 2015-17 simplifies the financial statement presentation of deferred tax assets and liabilities and requires an entity to present deferred tax assets and liabilities as noncurrent on the balance sheet. This guidance may be applied prospectively or retrospectively.

Sempra Energy adopted ASU 2015-17 on a prospective basis for the annual reporting period ended December 31, 2015, and the adoption did not affect its results of operations or cash flows. The Consolidated Balance Sheet at December 31, 2014 was not retrospectively adjusted.

ASU 2016-02, “Leases” (ASU 2016-02): ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to not recognize leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of accounting principles generally accepted in the United States of America (U.S. GAAP), other than certain changes to align lessor accounting to specific changes made to lessee accounting and ASU 2014-09, “Revenue from Contracts with Customers.” ASU 2016-02 also requires qualitative disclosures along with specific quantitative disclosures for both lessees and lessors.

For public entities, ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and is effective for interim periods in the year of adoption. The standard requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes optional practical expedients that may be elected, which would allow entities to continue to account for leases that commence before the effective date of the standard in accordance with previous U.S. GAAP unless the lease is modified, except for the lessee requirement to recognize right-of-use assets and lease liabilities for all operating leases at the reporting date. We are currently evaluating the effect of the standard on our ongoing financial reporting.

Note 3. Long-Term Debt

The following table shows the detail and maturities of long-term debt outstanding:

LONG-TERM DEBT
(Dollars in millions)
	December 31,			December 31,
	2015			2014(1)

6.5% Notes June 1, 2016, including $300 at variable rates after
fixed-to-floating rate swaps effective January 2011 (4.77% at December 31, 2015)	$	750		$	750
2.3% Notes April 1, 2017		600			600
6.15% Notes June 15, 2018		500			500
9.8% Notes February 15, 2019		500			500
2.4% Notes March 15, 2020		500			―
2.85% Notes November 15, 2020		400			―
2.875% Notes October 1, 2022		500			500
4.05% Notes December 1, 2023		500			500
3.55% Notes June 15, 2024		500			500
3.75% Notes November 15, 2025		350			―
6% Notes October 15, 2039		750			750
Market value adjustments for interest rate swaps, net		(2	)		―
Build-to-suit lease		136			75
		5,984			4,675
Current portion of long-term debt		(752	)		―
Unamortized discount on long-term debt		(10	)		(9	)
Unamortized debt issuance costs		(27	)		(22	)
Total long-term debt	$	5,195		$	4,644
(1) As adjusted for the retrospective adoption of ASU 2015-03.

Excluding the build-to-suit lease and market value adjustments for interest rate swaps, maturities of long-term debt are $750 million in 2016, $600 million in 2017, $500 million in 2018, $500 million in 2019, $900 million in 2020 and $2.6 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 4. Commitments and Contingencies

For contingencies and guarantees related to Sempra Energy, refer to Notes 4, 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, 2016

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, 2016

Principal Financial Officer: Joseph A. Householder Executive Vice President and Chief Financial Officer	/s/ Joseph A. Householder		February 26, 2016

Principal Accounting Officer: Trevor I. Mihalik Senior Vice President, Controller and Chief Accounting Officer	/s/ Trevor I. Mihalik		February 26, 2016

Directors:
Debra L. Reed, Chairman	/s/ Debra L. Reed		February 26, 2016

Alan L. Boeckmann, Director	/s/ Alan L. Boeckmann		February 26, 2016

James G. Brocksmith, Jr., Director	/s/ James G. Brocksmith, Jr.		February 26, 2016

Kathleen L. Brown, Director	/s/ Kathleen L. Brown		February 26, 2016

Pablo A. Ferrero, Director	/s/ Pablo A. Ferrero		February 26, 2016

William D. Jones, Director	/s/ William D. Jones		February 26, 2016

William G. Ouchi, Ph.D., Director	/s/ William G. Ouchi		February 26, 2016

William C. Rusnack, Director	/s/ William C. Rusnack		February 26, 2016

William P. Rutledge, Director	/s/ William P. Rutledge		February 26, 2016

Lynn Schenk, Director	/s/ Lynn Schenk		February 26, 2016

Jack T. Taylor, Director	/s/ Jack T. Taylor		February 26, 2016

James C. Yardley, Director	/s/ James C. Yardley		February 26, 2016

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/ J. Walker Martin
	J. Walker Martin Chairman, President and Chief Executive Officer

	Date: February 26, 2016


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: J. Walker Martin President and Chief Executive Officer	/s/ J. Walker Martin	February 26, 2016

Principal Financial and Accounting Officer: Bruce A. Folkmann Vice President, Controller, Chief Financial Officer and Chief Accounting Officer	/s/ Bruce A. Folkmann	February 26, 2016

Directors:
J. Walker Martin, Chairman	/s/ J. Walker Martin	February 26, 2016


Steven D. Davis, Director	/s/ Steven D. Davis	February 26, 2016


G. Joyce Rowland, Director	/s/ G. Joyce Rowland	February 26, 2016


Martha B. Wyrsch, Director	/s/ Martha B. Wyrsch	February 26, 2016

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/ Dennis V. Arriola
	Dennis V. Arriola Chairman, President and Chief Executive Officer

	Date: February 26, 2016


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: Dennis V. Arriola President and Chief Executive Officer	/s/ Dennis V. Arriola	February 26, 2016

Principal Financial and Accounting Officer: Bruce A. Folkmann Vice President, Controller, Chief Financial Officer and Chief Accounting Officer	/s/ Bruce A. Folkmann	February 26, 2016

Directors:
Dennis V. Arriola, Chairman	/s/ Dennis V. Arriola	February 26, 2016


Steven D. Davis, Director	/s/ Steven D. Davis	February 26, 2016


G. Joyce Rowland, Director	/s/ G. Joyce Rowland	February 26, 2016


J. Bret Lane, Director	/s/ J. Bret Lane	February 26, 2016


Martha B. Wyrsch, Director	/s/ Martha B. Wyrsch	February 26, 2016

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 1-03779 (San Diego Gas & Electric Company) and/or Commission File Number 1-01402 (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		Bylaws of Sempra Energy (as amended through December 15, 2015) (Sempra Energy Form 8-K
			filed on December 17, 2015, Exhibit 3.1).

	San Diego Gas & Electric Company (SDG&E)
	3.3		Amended and Restated Bylaws of San Diego Gas & Electric effective June 15, 2010 (SDG&E
			Form 8-K filed on June 17, 2010, Exhibit 3).

	3.4		Amended and Restated Articles of Incorporation of San Diego Gas & Electric Company
			effective August 15, 2014 (2014 Sempra Energy Form 10-K, Exhibit 3.4).

	Southern California Gas Company (SoCalGas)
	3.5		Amended and Restated Bylaws of Southern California Gas Company effective June 14, 2010
			(SoCalGas 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).

	Southern California Gas Company
	4.3		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
	4.4		Mortgage and Deed of Trust dated July 1, 1940 (SDG&E Registration Statement No. 2-4769,
			Exhibit B-3).

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

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

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

	4.8		Sixteenth Supplemental Indenture dated August 28, 1975 (SDG&E Registration Statement
			No. 33-34017, Exhibit 4.2).

	Sempra Energy / Southern California Gas Company
	4.9		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).

	4.10		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).

	4.11		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).

	4.12		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).

	4.13		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).

	4.14		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).

	4.15		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).

	Sempra Energy / San Diego Gas & Electric Company
	10.2		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).

	10.3		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
	10.4		Form of Sempra Energy Shared Services Executive Incentive Compensation Plan
			(2013 Sempra Energy Form 10-K, Exhibit 10.19).

	10.5		Amended and Restated Sempra Energy 2013 Long-Term Incentive Plan.

	10.6		Form of Sempra Energy 2013 Long-Term Incentive Plan 2016 Performance-Based Restricted
			Stock Unit Award - Relative Total Shareholder Return Performance Measure.

	10.7		Form of Sempra Energy 2013 Long-Term Incentive Plan 2016 Performance-Based Restricted
			Stock Unit Award - EPS Growth Performance Measure.

	10.8		Form of Sempra Energy 2013 Long-Term Incentive Plan 2016 Restricted Stock Unit Award.

	10.9		Form of Sempra Energy 2013 Long-Term Incentive Plan 2015 Performance-Based Restricted
			Stock Unit Award - Relative Total Shareholder Return Performance Measure (2014 Sempra
			Energy Form 10-K, Exhibit 10.19).

	10.10		Form of Sempra Energy 2013 Long-Term Incentive Plan 2015 Performance-Based Restricted
			Stock Unit Award - EPS Growth Performance Measure (2014 Sempra Energy Form 10-K,
			Exhibit 10.20).

	10.11		Form of Sempra Energy 2013 Long-Term Incentive Plan 2015 Performance-Based Restricted
			Stock Unit Award (2014 Sempra Energy Form 10-K, Exhibit 10.21).

	10.12		Form of Sempra Energy 2013 Long-Term Incentive Plan 2015 Restricted Stock Unit Award
			Agreement.

	10.13		Form of Sempra Energy 2013 Long-Term Incentive Plan 2014 Restricted Stock Unit Award
			(Sempra Energy March 31, 2014 Form 10-Q, Exhibit 10.1).

	10.14		Form of Sempra Energy 2013 Long-Term Incentive Plan 2014 Performance-Based Restricted
			Stock Unit Award - EPS Growth Performance Measure (Sempra Energy March 31, 2014
			Form 10-Q, Exhibit 10.2).

	10.15		Form of Sempra Energy 2013 Long-Term Incentive Plan 2014 Performance-Based Restricted
			Stock Unit Award - Relative Total Shareholder Return Performance Measure (Sempra
			Energy March 31, 2014 Form 10-Q, Exhibit 10.3).

	10.16		Form of Sempra Energy 2013 Long-Term Incentive Plan 2013 Performance-Based Restricted
			Stock Unit Award (Sempra Energy September 30, 2013 Form 10-Q, Exhibit 10.1).

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

	10.18		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).

	10.19		Form of Sempra Energy 2008 Long-Term Incentive Plan 2013 Restricted Stock
			Unit Award Agreement.

	10.20		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).

	10.21		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).

	10.22		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).

	10.23		Amended and Restated Sempra Energy 1998 Long-Term Incentive Plan (June 30, 2003
			Sempra Energy Form 10-Q, Exhibit 10.2).

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

	10.25		Amended and Restated Sempra Energy 2005 Deferred Compensation Plan,
			now known as Sempra Energy Employee and Director Retirement
			Savings Plan (June 30, 2015 Sempra Energy Form 10-Q, Exhibit 10.1).

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

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

	10.28		2009 Amendment and Restatement of the Sempra Energy Supplemental
			Executive Retirement Plan effective July 1, 2009.

	10.29		First Amendment to the 2009 Amendment and Restatement of the Sempra Energy Supplemental
			Executive Retirement Plan effective February 11, 2010.

	10.30		Second Amendment to the 2009 Amendment and Restatement of the Sempra Energy
			Supplemental Executive Retirement Plan effective January 1, 2014
			(2014 Sempra Energy Form 10-K, Exhibit 10.43).

	10.31		2015 Amendment and Restatement of the Sempra Energy Cash Balance Restoration Plan
			effective November 10, 2015.

	10.32		Sempra Energy Amended and Restated Executive Life Insurance Plan (2012 Sempra Energy
			Form 10-K, Exhibit 10.22).

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

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

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

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

	Sempra Energy

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

	10.38		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).

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

	10.40		Amended and Restated Sempra Energy Severance Pay Agreement between Sempra Energy
			and Mark A. Snell, dated November 4, 2008 (2014 Sempra Energy Form 10-K, Exhibit 10.53).

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

	10.42		Severance Pay Agreement between Sempra Energy and Martha B. Wyrsch, dated September
			3, 2013 (2013 Sempra Energy Form 10-K, Exhibit 10.57).

	10.43		Severance Pay Agreement between Sempra Energy and Steven D. Davis, dated December 31,
			2011 (2014 Sempra Energy Form 10-K, Exhibit 10.68).

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

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

	10.46		Form of Sempra Energy Non-Employee Directors’ Restricted Stock Unit Award (2014 Sempra
			Energy Form 10-K, Exhibit 10.59).

	10.47		Form of Sempra Energy Long Term Incentive Plan, Restricted Stock Unit Award
			for Sempra Energy’s Board of Directors (Sempra Energy June 30, 2010 Form 10-Q, Exhibit
			10.2).

	10.48		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).

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

	10.50		Amendment and Restatement of Sempra Energy 1998 Non-Employee Directors’ Stock Plan
			effective March 2, 1999 (2014 Sempra Energy Form 10-K, Exhibit 10.63).

	10.51		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).

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

	Sempra Energy / San Diego Gas & Electric Company
	10.53		Form of Sempra Energy and San Diego Gas & Electric Company Executive Incentive
			Compensation Plan (2013 Sempra Energy Form 10-K, Exhibit 10.64).

	10.54		Severance Pay Agreement between Sempra Energy and Jeffrey W. Martin, dated April 3,
			2010 (2013 Sempra Energy Form 10-K, Exhibit 10.65).

	10.55		Severance Pay Agreement between Sempra Energy and James P. Avery, dated February 18,
			2013 (Sempra Energy March 31, 2013 Form 10-Q, Exhibit 10.2).

	10.56		Severance Pay Agreement between Sempra Energy and Erbin Keith, dated February 18, 2013
			(Sempra Energy March 31, 2013 Form 10-Q, Exhibit 10.5).

	Sempra Energy / Southern California Gas Company
	10.57		Form of Sempra Energy and Southern California Gas Company Executive Incentive
			Compensation Plan (2013 Sempra Energy Form 10-K, Exhibit 10.71).

	10.58		Severance Pay Agreement between Sempra Energy and John C. Baker, dated February 18,
			2013 (2014 Sempra Energy Form 10-K, Exhibit 10.67).

	10.59		Severance Pay Agreement between Sempra Energy and Lee Schavrien, dated February 18,
			2013 (Sempra Energy March 31, 2013 Form 10-Q, Exhibit 10.3).

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

	10.61		Severance Pay Agreement between Sempra Energy and J. Bret Lane, dated August 4, 2012
			(2013 Sempra Energy Form 10-K, Exhibit 10.72).

	10.62		Severance Pay Agreement between Sempra Energy and Robert M. Schlax, dated January 17,
			2014 (2013 Sempra Energy Form 10-K, Exhibit 10.66).

	10.63		Severance Pay Agreement between Sempra Energy and Bruce Folkmann, dated
			August 4, 2012.

	10.64		Severance Pay Agreement between Sempra Energy and Sharon L. Tomkins, dated
			August 30, 2014.

	Nuclear

	Sempra Energy / San Diego Gas & Electric Company
	10.65		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).

	10.66		Amendment No. 1 to the Qualified CPUC Decommissioning Master Trust Agreement dated
			September 22, 1994 (see Exhibit 10.65 above) (1994 SDG&E Form 10-K, Exhibit 10.56).

	10.67		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 10.65 above) (1994 SDG&E Form 10-K, Exhibit 10.57).

	10.68		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 10.65 above) (1996 SDG&E Form 10-K, Exhibit 10.59).

	10.69		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 10.65 above) (1996 SDG&E Form 10-K, Exhibit 10.60).

	10.70		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 10.65 above) (1999 SDG&E Form 10-K, Exhibit 10.26).

	10.71		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 10.65 above) (1999 SDG&E Form 10-K, Exhibit 10.27).

	10.72		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 10.65 above) (2003 Sempra Energy Form 10-K, Exhibit
			10.42).

	10.73		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 10.65 above) (2011 SDG&E Form 10-K, Exhibit 10.70).

	10.74		Ninth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified
			CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station
			dated January 9, 2014 (see Exhibit 10.65 above) (2013 Sempra Energy Form 10-K,
			Exhibit 10.83).

	10.75		Tenth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified
			CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station
			dated August 27, 2014 (see Exhibit 10.65 above) (Sempra Energy September 30, 2014 Form
			10-Q, Exhibit 10.1).

	10.76		Eleventh Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified
			CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station
			dated August 27, 2014 (see Exhibit 10.65 above) (Sempra Energy September 30, 2014 Form
			10-Q, Exhibit 10.2).

	10.77		Twelfth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified
			CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station
			dated August 27, 2014 (see Exhibit 10.65 above) (Sempra Energy September 30, 2014 Form
			10-Q, Exhibit 10.3).

	10.78		Thirteenth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified
			CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station
			dated January 1, 2015 (see Exhibit 10.65 above).

	10.79		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).

	10.80		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 10.79 above) (1996 SDG&E Form 10-K, Exhibit 10.62).

	10.81		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 10.79 above) (1996 SDG&E Form 10-K, Exhibit 10.63).

	10.82		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 10.79 above) (1999 SDG&E Form 10-K, Exhibit 10.31).

	10.83		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 10.79 above) (1999 SDG&E Form 10-K, Exhibit 10.32).

	10.84		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 10.79 above) (2003 Sempra Energy Form 10-K, Exhibit
			10.48).

	10.85		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 10.79 above) (2011 SDG&E Form 10-
			K, Exhibit 10.77).

	10.86		Seventh Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-
			Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear
			Generating Station dated January 9, 2014 (see Exhibit 10.79 above) (2013 Sempra Energy
			Form 10-K, Exhibit 10.91).

	10.87		Eighth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-
			Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear
			Generating Station dated August 27, 2014 (see Exhibit 10.79 above) (Sempra Energy
			September 30, 2014 Form 10-Q, Exhibit 10.4).

	10.88		Ninth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-
			Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear
			Generating Station dated August 27, 2014 (see Exhibit 10.79 above) (Sempra Energy
			September 30, 2014 Form 10-Q, Exhibit 10.5).

	10.89		Tenth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-
			Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear
			Generating Station dated August 27, 2014 (see Exhibit 10.79 above) (Sempra Energy
			September 30, 2014 Form 10-Q, Exhibit 10.6).

	10.90		Eleventh Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-
			Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear
			Generating Station dated January 1, 2015 (see Exhibit 10.79 above).

	10.91		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).


	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, 2015, 2014, 2013, 2012 and 2011.

	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, 2015, 2014, 2013, 2012
			and 2011.

	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, 2015, 2014, 2013,
			2012 and 2011.


	EXHIBIT 13 -- ANNUAL REPORT TO SECURITY HOLDERS

	Sempra Energy / San Diego Gas & Electric Company / Southern California Gas Company
	13.1		Sempra Energy 2015 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, 2015.


	EXHIBIT 23 -- CONSENTS OF EXPERTS AND COUNSEL

	23.1		Consents of Independent Registered Public Accounting Firm and Report on Schedule, pages
			52 through 54.


	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 99 -- ADDITIONAL EXHIBITS

	Sempra Energy / Southern California Gas Company
	99.1		Press Release, including the Proclamation of a State of Emergency, by the Governor of the State
			of California, dated January 6, 2016 (Sempra Energy and SoCalGas Combined Form 8-K
			filed on January 7, 2016, Exhibit 99.1).


	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


AB	Assembly Bill	FTA	Free Trade Agreement
Annual Report	2015 Annual Report to Shareholders	GHG	Greenhouse gas
ASU	Accounting Standards Update	The Governor's Order	Proclamation of a State of Emergency, by the Governor of the State of California, dated January 6, 2016
Bay Gas	Bay Gas Storage Company, Ltd.	IEnova	Infraestructura Energética Nova, S.A.B. de C.V.
Bcf	Billion cubic feet (of natural gas)	IOUs	Investor-owned utilities
BMV	La Bolsa Mexicana de Valores, S.A.B. de C.V. (the Mexican Stock Exchange)	IRS	Internal Revenue Service
California Utilities	San Diego Gas & Electric Company and Southern California Gas Company	ISFSI	Independent spent fuel storage installations
Cameron LNG JV	Cameron LNG Holdings, LLC	ISO	Independent System Operator
CARB	California Air Resources Board	kV	Kilovolt
CCC	California Coastal Commission	kW	Kilowatt
CDEC	Centros de Despacho Económico de Carga (Centers for Economic Load Dispatch) (Chile)	LA Storage	LA Storage, LLC
CDEC-SIC	Sistema Interconectado Central (Central Interconnected System) (Chile)	LNG	Liquefied natural gas
CDEC-SING	Sistema Interconectado del Norte Grande (Northern Interconnected System) (Chile)	Luz del Sur	Luz del Sur S.A.A. and its subsidiaries
CEC	California Energy Commission	Mississippi Hub	Mississippi Hub, LLC
CFE	Comisión Federal de Electricidad	Mobile Gas	Mobile Gas Service Corporation
Chilquinta Energía	Chilquinta Energía S.A. and its subsidiaries	Mtpa	Million tonnes per annum
CNBV	Comisión Nacional Bancaria y de Valores (Mexican National Banking and Securities Commission)	MW	Megawatt
CNE	Comisión Nacional de Energía (National Energy Commission) (Chile)	MWh	Megawatt hours
COES	Comité de Operación Económica del Sistema Interconectado Nacional (Committee of Economic Operation of the National Interconnected System) (Peru)	NEM	Net energy metering
CPUC	California Public Utilities Commission	NRC	Nuclear Regulatory Commission
CRE	Comisión Reguladora de Energía (Energy Regulatory Commission) (Mexico)	NYK	Nippon Yusen Kabushiki Kaisha
DOE	U.S. Department of Energy	OSINERGMIN	Organismo Supervisor de la Inversión en Energía y Minería (Energy and Mining Investment Supervisory Body) (Peru)
DOGGR	California Department of Conservation's Division of Oil, Gas, and Geothermal Resources	PEMEX	Petróleos Mexicanos (Mexican state-owned oil company)
DOT	U.S. Department of Transportation	PG&E	Pacific Gas and Electric Company
Edison	Southern California Edison Company	PHMSA	Pipeline and Hazardous Materials Safety Administration
EPA	Environmental Protection Agency	PSEP	Pipeline Safety Enhancement Plan
EPC	Engineering, procurement and construction	QF	Qualifying Facility
ERR	Eligible Renewable Energy Resource	RBS Sempra Commodities	RBS Sempra Commodities LLP
FERC	Federal Energy Regulatory Commission	REX	Rockies Express pipeline

GLOSSARY (CONTINUED)


RNV	Registro Nacional de Valores (Mexican National Securities Registry)	SEC	Securities and Exchange Commission
Rockies Express	Rockies Express Pipeline LLC	SEIN	Sistema Eléctrico Interconectado Nacional (Peruvian national interconnected system)
RPS	Renewables Portfolio Standard	SoCalGas	Southern California Gas Company
SAESA	Sociedad Austral de Electricidad Sociedad Anónima	SONGS	San Onofre Nuclear Generating Station
SB	Senate Bill	The board	Sempra Energy's board of directors
SCAQMD	South Coast Air Quality Management District	TURN	The Utility Reform Network
SDG&E	San Diego Gas & Electric Company	UCAN	Utility Consumers’ Action Network
SDWA	Safe Drinking Water Act	Willmut Gas	Willmut Gas Company

Exhibit 10.5

Sempra Energy

2013 Long-Term Incentive Plan

(As Amended and Restated Effective December 15, 2015)

Contents

Article 1. Establishment, Purpose, and Duration

Article 2. Definitions

Article 3. Administration

Article 4. Shares Subject to This Plan and Maximum Awards

Article 5. Eligibility and Participation

Article 6. Stock Options

Article 7. Stock Appreciation Rights

Article 8. Restricted Stock and Restricted Stock Units

Article 9. Stock Payment Awards

Article 10. Dividend Equivalent Awards

Article 11. Cash-Based Awards

Article 12. Transferability of Awards

Article 13. Performance Measures

Article 14. Beneficiary Designation

Article 15. Rights of Participants

Article 16. Change in Control

Article 17. Amendment, Modification, Suspension, and Terminations

Article 18. Withholding

Article 19. Successors

Article 20. General Provisions

Sempra Energy

2013 Long-Term Incentive Plan

Article 1. Establishment, Purpose, and Duration

1.1 Establishment. Sempra Energy, a California corporation, has established an incentive compensation plan to be known as the Sempra Energy 2013 Long-Term Incentive Plan (the “Plan”), as set forth in this document. This Plan was previously approved by the Board of Directors of Sempra Energy and the shareholders of the Sempra Energy. This Plan became effective on May 10, 2013 (the “Effective Date”) and shall remain in effect as provided in Section 1.3 hereof.

This Plan permits the grant of Nonqualified Stock Options, Incentive Stock Options, Stock Appreciation Rights, Restricted Stock, Restricted Stock Units, Stock Payment Awards, Dividend Equivalent Awards and Cash-Based Awards.

The following provisions constitute an amendment, restatement, and continuation of the Plan as of December 15, 2015 (the “Approval Date”), the date the Board of Directors of Sempra Energy approved this amendment and restatement.

1.2 Purpose of This Plan. The purpose of this Plan is to provide compensation awards to Employees and Directors of the Company and its Subsidiaries that align the interests of such Employees and Directors with the interests of the Company and its shareholders. A further purpose of this Plan is to permit the Company and its Subsidiaries to attract and retain Employees or Directors and to provide Employees and Directors with an opportunity to acquire an equity interest in the Company.

1.3 Duration of This Plan. Unless sooner terminated as provided herein, this Plan shall terminate ten (10) years from the date of shareholder approval of this Plan. After this Plan is terminated, no Awards may be granted but Awards previously granted shall remain outstanding in accordance with their applicable terms and conditions and this Plan’s terms and conditions.

1.4 Prior Plans. No further grants shall be made under the Prior Plans, as defined in Article 2, from and after the Effective Date of this Plan.

Article 2. Definitions

Whenever used in this Plan, the following terms shall have the meanings set forth below, and when the meaning is intended, the initial letter of the word shall be capitalized.

2.1	“Affiliate” has the meaning set forth in Rule 12b-2 promulgated under the Exchange Act.

2.2	“Annual Award Limit” or “Annual Award Limits” have the meaning set forth in Section 4.3.

2.3

“Award” means, individually or collectively, a grant under this Plan of Nonqualified Stock Options, Incentive Stock Options, Stock Appreciation Rights, Restricted Stock, Restricted Stock Units, Stock Payment Awards, Dividend Equivalent Awards or Cash-Based Awards, in each case subject to the terms of this Plan.

2.4

“Award Agreement” means either: (a) a written agreement entered into by the Company and a Participant setting forth the terms and provisions applicable to an Award granted under this Plan, or (b) a written statement issued by the Company to a Participant setting forth the terms and provisions of such Award, including any amendment or modification thereof. The Committee may provide for the use of electronic, Internet, or other non-paper Award Agreements, and the use of electronic, Internet, or other non-paper means for the acceptance thereof and actions thereunder by a Participant.

2.5	“Beneficial Owner” or “Beneficial Ownership” shall have the meaning ascribed to such terms in Rule 13d-3 of the General Rules and Regulations under the Exchange Act.

2.6	“Board” or “Board of Directors” means the Board of Directors of the Company.

2.7	“Cash-Based Award” means an Award, settled in cash, granted under Article 11.

2.8

“Cause” shall mean, unless otherwise specified in an applicable employment or severance agreement, change in control severance agreement, change in control severance plan or Award Agreement, (i) the willful and continued failure by a Participant to substantially perform the Participant’s duties with the Company (other than any such failure resulting from the Participant’s incapacity due to physical or mental illness) or any such actual or anticipated failure after the issuance of a notice of termination for Good Reason by the Participant and/or (ii) the Participant’s commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty. For purposes of clause (i) of this Section 2.8, no act, or failure to act, on the Participant’s part shall be deemed “willful” unless done, or omitted to be done, by the Participant not in good faith and without reasonable belief that the Participant’s act, or failure to act, was in the best interests of the Company. Notwithstanding the foregoing, the Participant shall not be deemed terminated for Cause pursuant to clause (i) of this Section 2.8 unless and until the Participant shall have been provided with reasonable notice of and, if possible, a reasonable opportunity to cure the facts and circumstances claimed to provide a basis for termination of the Participant’s employment for Cause.

2.9

“Change in Control” shall mean a change in the ownership of the Company, a change in the effective control of the Company, or a change in the ownership of a substantial portion of assets of the Company (each, as defined in subsection (a) below), except as otherwise provided in subsections (b), (c) and (d) below:

(a)(i)

a “change in the ownership of the Company” occurs on the date that any one person, or more than one person acting as a group, acquires ownership of stock of the Company that, together with stock held by such person or group, constitutes more than fifty percent (50%) of the total Fair Market Value or total voting power of the stock of the Company,

(ii)

a “change in the effective control of the Company” occurs only on either of the following dates:

(A)

the date any one person, or more than one person acting as a group, acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of the Company possessing thirty percent (30%) or more of the total voting power of the stock of the Company, or

(B)

the date a majority of the members of the Board is replaced during any twelve (12) month period by directors whose appointment or election is not endorsed by a majority of the members of the Board before the date of appointment or election, and

(iii)

a “change in the ownership of a substantial portion of assets of the Company” occurs on the date any one person, or more than one person acting as a group, acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by such person or persons) assets from the Company that have a total gross fair market value equal to or more than eighty-five percent (85%) of the total gross fair market value of all of the assets of the Company immediately before such acquisition or acquisitions.

(b)

A “change in the ownership of the Company” or “a change in the effective control of the Company” shall not occur under clause (a)(i) or (a)(ii) by reason of any of the following:

(i)

an acquisition of ownership of stock of the Company directly from the Company or its Affiliates other than in connection with the acquisition by the Company or its Affiliates of a business,

(ii)

a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof), in combination with the ownership of any trustee or other fiduciary holding securities under an employee benefit plan of the Company, at least sixty percent (60%) of the combined voting power of the securities of the Company or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation, or

(iii)

a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no Person is or becomes the Beneficial Owner, directly or indirectly, of securities of the Company (not including the securities beneficially owned by such Person any securities acquired directly from the Company or its Affiliates other than in connection with the acquisition by the Company or its Affiliates of a business) representing twenty percent (20%) or more of the combined voting power of the Company’s then outstanding securities.

(c)

A “change in the ownership of a substantial portion of assets of the Company” shall not occur under clause (a)(iii) by reason of a sale or disposition by the Company of the assets of the Company to an entity, at least sixty percent (60%) of the combined voting power of the voting securities of which are owned by shareholders of the Company in substantially the same proportions as their ownership of the Company immediately prior to such sale.

(d)

This definition of “Change in Control” shall be limited to the definition of a “change in control event” relating to the Company under Treasury Regulation Section 1.409A-3(i)(5). A “Change in Control” shall only occur if there is a “change in control event” relating to the Company under Treasury Regulation Section 1.409A-3(i)(5) with respect to the applicable Participant.

2.10	“Code” means the U.S. Internal Revenue Code of 1986, as amended from time to time. For purposes of this Plan, references to sections of the Code shall be deemed to include references to any applicable regulations thereunder and any successor or similar provision.

2.11

“Committee” means the Compensation Committee of the Board or a subcommittee thereof, or any other committee designated by the Board to administer this Plan. The members of the Committee shall be appointed from time to time by and shall serve at the discretion of the Board. The Committee shall consist solely of two or more Directors, each of whom shall qualify as both an “outside director” for purposes of Code Section 162(m) and a “non-employee director” as defined in Rule 16b-3 promulgated under the Exchange Act.

2.12	“Company” means Sempra Energy, a California corporation, and any successor thereto as provided in Article 19 herein.

2.13	“Covered Employee” means any Employee who is or may become a “covered employee,” as defined in the regulations promulgated under Code Section 162(m).

2.14	“Director” means any individual who is a member of the Board of Directors of the Company.

2.15	“Disability” has the meaning set forth in the long-term disability plan maintained by the employer of the applicable Participant or a successor entity to such employer.

2.16	“Dividend Equivalent” means a right to receive Shares, or cash, granted to a Participant pursuant to Article 10.

2.17	“Effective Date” has the meaning set forth in Section 1.1.

2.18	“Eligible Individual” means any individual eligible to participate in this Plan, as set forth in Article 5.

2.19	“Employee” means any officer or other employee (as defined in accordance with Code Section 3401(c)) of the Company or any Subsidiary.

2.20

“Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time, or any successor act thereto. For purposes of this Plan, references to sections of the Exchange Act shall be deemed to include references to any applicable regulations thereunder and any successor or similar provision.

2.21	“Fair Market Value” or “FMV” means, as of any date, the value of a Share determined as follows:

(a)

if Shares are listed on any established stock exchange (such as the New York Stock Exchange, the NASDAQ Global Market and the NASDAQ Global Select Market) or any national market system, including without limitation any market system of The NASDAQ Stock Market, LLC, the value of a Share shall be the closing sales price for a Share as quoted on the principal exchange or system on which Shares are listed for such date (or, if there is no closing sales price for a Share on the date in question, the closing sales price for a Share on the next preceding trading day for which such information exists), as reported in The Wall Street Journal or such other source as the Board or the Committee deems reliable;

(b)

if Shares are regularly quoted by a recognized securities dealer but closing sales prices are not reported, the value of a Share shall be the mean of the high bid and low asked prices for such date (or, if there are no high bid and low asked prices for a Share on the date in question, the high bid and low asked prices for a Share on the next preceding trading day for which such information exists), as reported in The Wall Street Journal or such other source as the Board or the Committee deems reliable; or

(c)

if Shares are neither listed on an established stock exchange or a national market system nor regularly quoted by a recognized securities dealer, the value of a Share for such date, as established by the Board or the Committee in good faith.

(d)

For purposes of any Nonqualified Stock Option or SAR that is intended to be exempt from Code Section 409A pursuant to Treasury Regulation Section 1.409A-1(b)(5), FMV shall be not less than the fair market value of a Share determined in accordance with the requirements of Treasury Regulation Section 1.409A-1(b)(5)(iv).

2.22

“Good Reason” shall mean, unless otherwise specified in an applicable employment or severance agreement, change in control severance agreement, change in control severance plan or Award Agreement, the occurrence of any of the following without the prior written consent of the Participant, unless such act or failure to act is corrected by the Company prior to the date of termination specified in a Participant’s notice of termination (which notice of termination must be provided to the Company within one hundred eighty (180) days of the act or failure to act that the Participant alleges to constitute Good Reason and shall identify a date of termination that in no event shall be less than fifteen (15) days nor more than sixty (60) days after the date such notice of termination is given):

(a)	an adverse change in the Participant’s title, authority, duties, responsibilities or reporting lines as in effect immediately prior to the Change in Control;

(b)

a reduction by the Company in the Participant’s aggregate annualized compensation opportunities, except for across-the-board reductions in base salaries, annual bonus opportunities or long-term incentive compensation opportunities of less than ten percent (10%) similarly affecting all similarly situated employees (both of the Company and of any Person then in control of the Company) of comparable rank with the Participant; or the failure by the Company to continue in effect any material benefit plan in which the Participant participates immediately prior to the Change in Control, unless an equitable arrangement (embodied in an ongoing substitute or alternative plan) has been made with respect to such plan, or the failure by the Company to continue the Participant’s participation therein (or in such substitute or alternative plan) on a basis not materially less favorable, both in terms of the amount of benefits provided and the level of the Participant’s participation relative to other participants, as existed at the time of the Change in Control;

(c)

the relocation of the Participant’s principal place of employment immediately prior to the consummation of the Change in Control (the “Principal Location”) to a location which is both further away from the Participant’s residence and more than thirty (30) miles from such Principal Location, or the Company’s requiring the Participant to be based anywhere other than such Principal Location (or permitted relocation thereof), or a substantial increase in the Participant’s business travel obligations outside of the general area of the Principal Location as of the date of consummation of a Change in Control, other than any such increase that (A) arises in connection with extraordinary business activities of the Company of limited duration and (B) is understood not to be part of the Participant’s regular duties with the Company;

(d)

the failure by the Company to pay to the Participant any portion of the Participant’s current compensation and benefits or any portion of an installment of deferred compensation under any deferred compensation program of the Company within thirty (30) days of the date such compensation is due, accounting for any six-month delay in payment as required to comply with Section 409A of the Code;

(e)

any purported termination of the Participant’s employment that is not effected pursuant to a notice of termination that sets forth in reasonable detail the facts and circumstances for such termination;

(f)

the failure by the Company to provide any indemnification and/or D&O insurance protection that it is required to be provided to the Participant under any agreement between the Company and the Participant; or

(g)

the failure by the Company to comply with any material provision of any material agreement between the Company and the Participant.

For purposes of this Section 2.22, a Participant’s determination that an act or failure to act constitutes Good Reason shall be presumed to be valid unless such determination is deemed to be unreasonable by the finder of fact pursuant to the dispute resolution procedure described in Section 16.4 hereof. The Participant’s right to terminate the Participant’s employment for Good Reason shall not be affected by the Participant’s incapacity due to physical or mental illness. The Participant’s continued employment shall not constitute consent to, or a waiver of rights with respect to, any act or failure to act constituting Good Reason hereunder.

2.23	“Grant Date” means the date an Award is granted to a Participant pursuant to the Plan.

2.24	“Incentive Stock Option” or “ISO” means a stock option granted under Article 6 to an Employee that satisfies the requirements of Code Section 422, or any successor provision, and that is designated as an “Incentive Stock Option.”

2.25	“Nonemployee Director” means a Director who is not an Employee.

2.26	“Nonemployee Director Award” means any NQSO, SAR, or other Award granted, whether singly, in combination, or in tandem, to a Participant who is a Nonemployee Director pursuant to such applicable terms, conditions, and limitations as the Board may establish in accordance with this Plan.

2.27

“Nonqualified Stock Option” or “NQSO” means a stock option that does not meet the requirements of Code Section 422, or that is designated as a “Nonqualified Stock Option.” A stock option that is designated as a “Nonqualified Stock Option” shall not be treated as an incentive stock option under Code Section 422.

2.28	“Option” means an Incentive Stock Option or a Nonqualified Stock Option, as described in Article 6.

2.29	“Option Price” means the price at which a Share may be purchased by a Participant pursuant to an Option.

2.30	“Participant” means any Eligible Individual to whom an Award is granted.

2.31	“Performance-Based Compensation” means compensation under an Award that is intended to satisfy the requirements for qualified performance-based compensation under Code Section 162(m) paid to Covered Employees.

2.32	“Performance Measures” means measures as described in Article 11 on which the performance goals are based and which are approved by the Company’s shareholders pursuant to this Plan in order to qualify Awards as Performance-Based Compensation.

2.33	“Performance Period” means the period of time during which the performance goals must be met in order to determine the degree of exercisability, vesting, distribution or payment with respect to an Award.

2.34

“Period of Restriction” means the period when Restricted Stock or Restricted Stock Units are subject to a substantial risk of forfeiture (based on the performance of services, the achievement of performance goals, or upon the occurrence of other events as determined by the Committee, in its sole discretion), as provided in Article 8.

2.35	“Person” shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including a “group” as defined in Section 13(d) thereof.

2.36	“Plan” means the Sempra Energy 2013 Long-Term Incentive Plan, as amended from time to time.

2.37	“Plan Year” means the calendar year.

2.38

“Prior Plans” means, collectively, the Sempra Energy 2008 Long-Term Incentive Plan, the 2008 Long-Term Incentive Plan for EnergySouth, Inc. Employees and other Eligible Individuals, the Sempra Energy 1998 Long Term Incentive Plan, the Sempra Energy 1998 Non-Employee Directors’ Stock Plan, and the Sempra Energy Employee Stock Incentive Plan, in each case, as amended from time to time.

2.39	“Restricted Stock” means Shares awarded to a Participant pursuant to Article 8 that are subject to restrictions and may be subject to forfeiture or repurchase.

2.40	“Restricted Stock Unit” means a right to receive Shares, or cash, granted to a Participant pursuant to Article 8.

2.41	“Retirement” means a Participant’s termination of employment at age 55 or older with five (5) years or more years of continuous service with the Company and its Subsidiaries.

2.42	“Rule 16b-3” means Rule 16b-3 of the General Rules and Regulations under the Exchange Act, as such Rule may be amended from time to time.

2.43	“SAR Grant Price” means the per Share price established for a SAR pursuant to Article 7, used to determine whether there is any payment due upon exercise of the SAR.

2.44	“Share” means a share of common stock of the Company, no par value per share.

2.45	“Stock Appreciation Right” or “SAR” means a stock appreciation right granted to a Participant pursuant to Article 7.

2.46	“Stock Payment Award” means a grant of Shares, or a right to receive Shares, granted to a Participant pursuant to Article 9.

2.47

“Subsidiary” means: (a) any corporation or other entity (other than the Company), whether domestic or foreign, in which the Company has or obtains, directly or indirectly, a proprietary interest of more than fifty percent (50%) by reason of stock ownership or otherwise, or (b) any corporation or other entity (including, but not limited to, a partnership or a limited liability company), that is affiliated with the Company through stock or equity ownership or otherwise, and is designated as a Subsidiary for purposes of this Plan by the Committee.

2.48

“Subsidiary Corporation” shall mean any corporation in an unbroken chain of corporations beginning with the Company if each of the corporations other than the last corporation in the unbroken chain then owns stock possessing fifty percent (50%) or more of the total combined voting power of all classes of stock in one of the other corporations in such chain.

2.49

“Ten Percent Shareholder” or “10% Shareholder” means the owner of stock (as determined under Code Section 424(d)) possessing more than ten percent (10%) of the total combined voting power of all classes of stock of the Company, or any parent corporation (as defined in Code Section 424(e)) of the Company or any Subsidiary Corporation.

Article 3. Administration

3.1 General. The Committee shall be responsible for administering this Plan, subject to this Article 3 and the other provisions of this Plan. The Committee may employ attorneys, consultants, accountants, agents, and other individuals, any of whom may be an Employee and the Committee, the Company, and its officers and Directors shall be entitled to rely upon the advice, opinions, or valuations of any such individuals. No member of the Committee shall be liable for any action or determination made in good faith with respect to the Plan or any grant made hereunder. Determinations by the Committee under this Plan need not be uniform and may be made selectively among Participants. All actions taken and all interpretations and determinations made by the Committee shall be final, conclusive and binding upon the Participants, the Company, and all other interested parties. For the avoidance of doubt, a Participant’s determination that an act or failure to act constitutes Good Reason shall be presumed to be valid unless such determination is deemed to be unreasonable by the finder of fact pursuant to the dispute resolution procedure described in Section 16.4 hereof.

3.2 Authority of the Committee. The Committee shall have full and exclusive discretionary power to interpret the terms and the intent of this Plan and any Award Agreement or other agreement or document ancillary to or in connection with this Plan, to determine eligibility for Awards, and to adopt such rules, regulations, forms, instruments, and guidelines for administering this Plan as the Committee may deem necessary or proper. Such authority shall include, but not be limited to, selecting Award recipients, establishing all Award terms and conditions, including the terms and conditions set forth in Award Agreements, granting Awards in lieu of, or in satisfaction of, compensation earned or to be paid under other compensation plans or agreements of the Company or any Subsidiary, construing any provision of the Plan or any Award Agreement, and, subject to Article 16, adopting modifications and amendments to this Plan or any Award Agreement, including without limitation, any that are necessary to comply with the laws of the countries and other jurisdictions in which the Company and/or its Subsidiaries operate.

3.3 Delegation. This Committee may delegate to one or more of its members or to one or more officers of the Company and/or its Subsidiaries, or to one or more agents or advisors such administrative duties or powers as it may deem advisable, and the Committee or any individuals to whom it has delegated duties or powers as aforesaid may employ one or more individuals to render advice with respect to any responsibility the Committee or such individuals may have under this Plan. The Committee may authorize one or more officers of the Company to do one or both of the following on the same basis as can the Committee, to the extent permitted by applicable law: (a) designate Employees to be recipients of Awards, and (b) determine the size of any such Awards; provided, however, that: (i) the Committee shall not delegate such responsibilities to any such officer for Awards granted to an Employee who is subject to the reporting rules as promulgated in accordance with Section 16 of the Exchange Act; and (ii) the officer(s) shall report periodically to the Committee regarding the nature and scope of the Awards granted pursuant to the authority delegated.

3.4 Nonemployee Director Awards. The Board shall be responsible for administering this Plan with respect to Awards to Nonemployee Directors, subject to the provisions of this Plan. With respect to the administration of the Plan as it relates to Awards granted to Nonemployee Directors, references in this Plan to the “Committee” shall refer to the Board.

Article 4. Shares Subject to This Plan and Maximum Awards

4.1 Number of Shares Available for Awards. Subject to adjustment as provided in Section 4.4 herein:

(a)

The maximum number of Shares available for issuance to Participants under this Plan (the “Share Authorization”) shall be the sum of:

(i)

Five Million Nine Hundred Thousand (5,900,000) Shares (the “Initial Authorized Shares”), plus

(ii)

the number of Shares not issued or subject to outstanding awards under (a) the Sempra Energy 2008 Long-Term Incentive Plan and (b) the 2008 Long-Term Incentive Plan for EnergySouth, Inc. Employees and other Eligible Individuals, in each case as of the Effective Date, plus

(iii)

the number of Shares subject to outstanding awards as of the Effective Date under the Prior Plans that on or after the Effective Date cease for any reason to be subject to such awards (other than the vested and nonforfeitable Shares that are issued pursuant to such awards and are not withheld or surrendered in satisfaction of the exercise price or taxes relating to such awards) (the “Cancelled Prior Award Shares”).

(b)	The maximum number of Shares of the Share Authorization that may be issued pursuant to ISOs under this Plan shall be Five Million Nine Hundred Thousand (5,900,000) Shares.

4.2 Share Usage. Any Shares related to Awards under this Plan which terminate by expiration, forfeiture, cancellation, or otherwise, without the issuance of such Shares, shall be available again for grant under this Plan. Shares withheld or surrendered in satisfaction of the exercise price or taxes relating to an award under this Plan shall not constitute shares issued to Participants and shall be available for grant under this Plan; provided that in no event for Option and SAR grants made on or after the Approval Date shall shares withheld or surrendered in payment of the exercise price of an option or SAR or to satisfy tax withholding liabilities arising from the exercise or settlement of an option or SAR be available again for grant under this Plan. Furthermore, if a SAR is exercised and settled in Shares under this Plan, the difference between the total Shares exercised and the net Shares delivered shall be available again for grant under this Plan, with the result being that only the number of Shares issued upon exercise of a SAR will be counted against the Shares available; provided, however, that for SAR grants made on or after the Approval Date, upon stock settlement of SARs, the gross number of SARs originally granted shall be counted as issued for purposes of determining whether the shares authorization has been reached, regardless of the number of SARs actually issued upon such stock settlement. Notwithstanding anything to the contrary in this Section 4.2, the full number of Shares subject to an Option, SAR or other Award shall be counted for purposes of determining compliance with the Annual Award Limits set forth in Section 4.3. The payment of dividend equivalents in cash in conjunction with any outstanding Award shall not be counted against the Shares available for issuance under the Plan. Notwithstanding the provisions of this Section 4.2, no Shares may again be optioned, granted or awarded if such action would cause an Incentive Stock Option to fail to qualify as an incentive stock option under Code Section 422.

4.3 Annual Award Limits. The following limits (each an “Annual Award Limit,” and collectively, “Annual Award Limits”), as adjusted pursuant to Section 4.4, shall apply to grants of Awards under this Plan:

(a)

Awards (other than Option, SAR and Cash-Based Awards). The maximum aggregate number of Shares subject to Restricted Stock, Restricted Stock Units, Stock Payment Awards and Dividend Equivalent Awards granted in any Plan Year to any Participant other than a Nonemployee Director shall be Five Hundred Thousand (500,000).

(b)

Option and SAR Awards. The maximum aggregate number of Shares subject to Option and SAR Awards granted in any Plan Year to any Participant other than a Nonemployee Director shall be Five Hundred Thousand (500,000).

(c)

Cash-Based Awards: The maximum aggregate amount awarded with respect to Cash-Based Awards to any Participant other than a Nonemployee Director in any Plan Year shall be Ten Million dollars ($10,000,000).

(d)

Nonemployee Director Awards. The maximum number of Shares subject to Options, SAR Awards, Restricted Stock, Restricted Stock Units, Stock Payment Awards and Dividend Equivalent Awards granted in any Plan Year to any Participant who is a Nonemployee Director shall be Fifteen Thousand (15,000). The maximum aggregate amount awarded with respect to Cash-Based Awards to any Participant who is a Nonemployee Director in any Plan Year shall be Five Hundred Thousand dollars ($500,000).

4.4 Adjustments in Authorized Shares. In the event of any corporate event or transaction (including, but not limited to, a change in the Shares or the capitalization of the Company) such as a merger, consolidation, reorganization, recapitalization, separation, partial or complete liquidation, stock dividend, special cash dividend, stock split, reverse stock split, split up, spin-off, or other distribution of stock or property of the Company, combination of Shares, exchange of Shares, dividend in-kind, or other like change in capital structure, number of outstanding Shares or distribution (other than normal cash dividends) to shareholders of the Company, or any similar corporate event or transaction, the Committee shall, in order to prevent dilution or enlargement of Participants’ rights under this Plan and outstanding awards, substitute or adjust, as applicable, the number and kind of Shares (or other securities) that may be issued under this Plan or under particular forms of Awards, the number and kind of Shares (or other securities) subject to outstanding Awards, the Option Price or SAR Grant Price applicable to outstanding Awards, the Annual Award Limits and the terms and conditions of outstanding Awards. Notwithstanding anything herein to the contrary, the Committee may not take any such action as described in this Section 4.4 that would cause an Award that is otherwise exempt from Code Section 409A to become subject to Code Section 409A, or cause an Award that is subject to the requirements of Code Section 409A to fail to comply with such requirements, or cause an Award that is Performance-Based Compensation to fail to satisfy the requirements for qualified performance-based compensation under Code Section 162(m). The determination of the Committee as to the foregoing adjustments, if any, shall be final, conclusive and binding on the Company and all Participants and other parties having any interest in an Award under this Plan.

Subject to the provisions of Article 17 and notwithstanding anything else herein to the contrary, without affecting the number of Shares reserved or available hereunder, the Committee may authorize the grant of substitute Awards under this Plan in connection with any merger, consolidation, acquisition of property or stock, or reorganization upon such terms and conditions as it may deem appropriate, subject to compliance with the rules under Code Sections 162(m), 409A, 422, and 424, as and where applicable.

Article 5. Eligibility and Participation

5.1 Eligibility. Individuals eligible to participate in this Plan include all Employees and Directors.

5.2 Actual Participation. Subject to the provisions of this Plan, the Committee may, from time to time, select from all Eligible Individuals, those to whom Awards shall be granted and shall determine, in its sole discretion, the nature of, any and all terms permissible by law, and the amount of each Award.

Article 6. Stock Options

6.1 Grant of Options. Subject to the terms and conditions of this Plan, Options may be granted to any Eligible Individual in such number, and upon such terms, and at any time and from time to time as shall be determined by the Committee, in its sole discretion; provided that ISOs may be granted only to Employees of the Company or any Subsidiary Corporation.

6.2 Stock Option Agreement. Each Option grant shall be evidenced by an Award Agreement that shall specify the Option Price, the maximum duration of the Option, the number of Shares to which the Option pertains, the conditions upon which an Option shall become vested and exercisable, the extent to which the Participant shall have the right to exercise the Option following termination of the Participant’s employment with or provision of services to the Company and/or its Subsidiaries, and such other provisions as the Committee shall determine which are not inconsistent with the terms of this Plan. The Award Agreement also shall specify whether the Option is intended to be an ISO or a NQSO.

6.3 Option Price. The Option Price for each grant of an Option under this Plan shall be determined by the Committee in its sole discretion and shall be specified in the Award Agreement; provided, however, the Option Price must be at least equal to one hundred percent (100%) of the FMV of the Shares as determined on the Grant Date.

6.4 Term of Options. Each Option granted to a Participant shall expire at such time as the Committee shall determine at the time of grant; provided, however, no Option shall be exercisable on or after the tenth (10th) anniversary date of its grant.

6.5 Exercise of Options. Options granted under this Article 6 shall be exercisable at such times and be subject to such restrictions and conditions as the Committee shall in each instance approve, which terms and restrictions need not be the same for each grant or for each Participant. On the expiration date of any outstanding, vested Option, if the aggregate Fair Market Value of the Shares subject to the unexercised Option exceeds the aggregate exercise price of the unexercised Option by at least $50.00, such Option shall automatically be exercised at the Fair Market Value of a Share on such day, with the number of Shares, less the number of Shares withheld to pay the exercise price and taxes, delivered to the Participant, provided that such Option shall not be so exercised if the Option Price equals or exceeds the Fair Market Value of a Share on such day.

6.6 Payment. Options granted under this Article 6 shall be exercised by the delivery of a notice of exercise to the Company or an agent designated by the Company in a form specified or accepted by the Committee, or by complying with any alternative procedures which may be authorized by the Committee, setting forth the number of Shares with respect to which the Option is to be exercised, accompanied by full payment for the Shares.

A condition of the issuance of the Shares as to which an Option shall be exercised shall be the payment of the Option Price. The Option Price of any Option shall be payable to the Company in full, in cash or its equivalent or by a cashless (broker-assisted) exercise (with such cashless exercise to be subject to any terms and conditions as the Committee may impose, in its sole direction), or under such other methods as are authorized by the Committee, in its sole discretion, including, without limitation: (a) by tendering (either by actual delivery or attestation) previously acquired Shares having an aggregate Fair Market Value at the time of exercise equal to the Option Price; (b) by surrendering Shares then issuable upon exercise of the Option having an aggregate Fair Market Value at the time of exercise equal to the Option Price; or (c) by a combination of the foregoing, subject to such terms and conditions as the Committee, in its sole discretion, may impose; provided, however, that in the case of an ISO, the payment methods shall be set forth in the Award Agreement.

Subject to any governing rules or regulations, as soon as practicable after receipt of written notification of exercise and full payment (including satisfaction of any applicable tax withholding), the Company shall deliver to the Participant evidence of book entry Shares, or upon the Participant’s request, Share certificates in an appropriate amount based upon the number of Shares purchased under the Option.

Unless otherwise determined by the Committee, all payments under all of the methods indicated above shall be paid in United States dollars.

6.7 Restrictions. The Committee may impose such restrictions on any Shares acquired pursuant to the exercise of an Option granted under this Article 6 as it may deem advisable, including, without limitation, minimum holding period requirements, restrictions under the policies of the Company or any Subsidiary, restrictions under applicable federal, state and foreign laws or under the requirements of any stock exchange or market upon which such Shares are then listed and/or traded.

6.8 Termination of Employment. Each Participant’s Award Agreement shall set forth the extent to which the Participant shall have the right to exercise the Option following termination of the Participant’s employment with or provision of services to the Company and/or its Subsidiaries, as the case may be. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with each Participant, need not be uniform among all Options issued pursuant to this Plan, and may reflect distinctions based on the reasons for termination.

6.9 Notification of Disqualifying Disposition. If any Participant shall make any disposition of Shares issued pursuant to the exercise of an ISO under the circumstances described in Code Section 421(b) (relating to certain disqualifying dispositions), such Participant shall notify the Company of such disposition within ten (10) days thereof.

6.10 10% Shareholder. If any Employee to whom an Incentive Stock Option is granted is a 10% Shareholder, then the Option Price shall be at least equal to one hundred ten percent (110%) of the FMV of the Shares as determined on the Grant Date and the term of the Option shall not exceed five (5) years measured from the Grant Date.

6.11 $100,000 Limitation. To the extent that the aggregate fair market value of Shares and other stock with respect to which Incentive Stock Options or other “incentive stock options” (within the meaning of Code Section 422, but without regard to Code Section 422(d)) granted under the Plan and all other plans of the Company and any Subsidiary Corporation or any parent corporation thereof (as defined in code Section 424(e)) are exercisable for the first time by a Participant during any calendar year exceeds $100,000, the Incentive Stock Options or other “incentive stock options” shall be treated as Nonqualified Stock Options to the extent required by Code Section 422. The rule set forth in the preceding sentence shall be applied by taking Incentive Stock Options and other “incentive stock options” into account in the order in which they were granted. For purposes of this Section 6.11, the fair market value of shares or other stock shall be determined as of the time the Incentive Stock Option or other “incentive stock options” with respect to such shares or other stock is granted.

Article 7. Stock Appreciation Rights

7.1 Grant of SARs. Subject to the terms and conditions of this Plan, SARs may be granted to Eligible Individuals at any time and from time to time as shall be determined by the Committee.

Subject to the terms and conditions of this Plan, the Committee shall have complete discretion in determining the number of SARs granted to each Participant and in determining the terms and conditions pertaining to such SARs which are not inconsistent with the terms of this Plan.

The SAR Grant Price for each grant of a SAR shall be determined by the Committee and shall be specified in the Award Agreement; provided, however, the SAR Grant Price must be at least equal to one hundred percent (100%) of the FMV of the Shares as determined on the Grant Date.

7.2 SAR Agreement. Each SAR Award shall be evidenced by an Award Agreement that shall specify the SAR Grant Price, the term of the SAR, the number of Shares to which the SAR pertains, the form of the SAR payout, the conditions upon which any SAR shall become vested and exercisable, the extent to which the Participant shall have the right to exercise the SAR following termination of the Participant’s employment with or provision of services to the Company and/or its Subsidiaries and such other provisions as the Committee shall determine which are not inconsistent with the terms of this Plan.

7.3 Term of SAR. Each SAR granted to a Participant shall expire at such time as the Committee shall determine at the time of grant; provided, however, no SAR shall be exercisable on or after the tenth (10th) anniversary date of its grant.

7.4 Exercise of SARs. SARs granted under this Article 7 shall be exercised at such times and be subject to such restrictions and conditions as the Committee shall in each instance approve, which terms and restrictions need not be the same for each grant or for each Participant.

7.5 Settlement of SARs. Upon the exercise of a SAR, a Participant shall be entitled to receive payment from the Company in an amount determined by multiplying:

(a)

The excess of the Fair Market Value of a Share on the date of exercise over the SAR Grant Price; by

(b)

The number of Shares with respect to which the SAR is exercised.

At the discretion of the Committee, the payment upon SAR exercise may be in cash, Shares, or any combination thereof. The Committee’s determination regarding the form of SAR payout shall be set forth in the Award Agreement pertaining to the grant of the SAR.

7.6 Termination of Employment. Each Participant’s Award Agreement shall set forth the extent to which the Participant shall have the right to exercise the SAR following termination of the Participant’s employment with or provision of services to the Company and/or its Subsidiaries, as the case may be. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with each Participant, need not be uniform among all SARs issued pursuant to this Plan, and may reflect distinctions based on the reasons for termination.

7.7 Restrictions. The Committee may impose such restrictions on any Shares acquired pursuant to the exercise of a SAR granted under this Article 7 as it may deem advisable, including, without limitation, minimum holding period requirements, restrictions under applicable federal, state and foreign securities laws or under the requirements of any stock exchange or market upon which such Shares are then listed and/or traded.

Article 8. Restricted Stock and Restricted Stock Units

8.1 Grant of Restricted Stock or Restricted Stock Units. Subject to the terms and conditions of this Plan, the Committee, at any time and from time to time, may grant Shares of Restricted Stock and/or Restricted Stock Units to Participants in such number of Shares as the Committee shall determine. Restricted Stock Units shall be similar to Restricted Stock except that no Shares are issued to the Participant on the Grant Date and any Shares that are to be issued shall be issued to the Participant after the Grant Date, subject to the terms and conditions of the Award.

8.2 Restricted Stock or Restricted Stock Unit Agreement. Each Restricted Stock or Restricted Stock Unit grant shall be evidenced by an Award Agreement that shall specify the Period(s) of Restriction, the number of Shares of Restricted Stock or the number of Restricted Stock Units granted, the extent to which the Participant shall have the right to retain Restricted Stock and/or Restricted Stock Units following termination of the Participant’s employment with or provision of services to the Company and/or its Subsidiaries, and such other provisions as the Committee shall determine which are not inconsistent with the terms of this Plan.

8.3 Restrictions. The Committee shall impose such other conditions and/or restrictions on any Shares of Restricted Stock or Restricted Stock Units granted pursuant to this Plan as it may deem advisable including, without limitation, a requirement that Participants pay a stipulated purchase price for each Share of Restricted Stock or each Restricted Stock Unit, restrictions based upon the achievement of specific performance goals, service-based restrictions on vesting following the attainment of the performance goals, service-based restrictions, and/or restrictions under applicable laws or under the requirements of any stock exchange or market upon which such Shares are listed or traded, or holding requirements or sale restrictions placed on the Shares by the Company upon vesting of such Restricted Stock or Restricted Stock Units.

To the extent deemed appropriate by the Committee, the Company may retain the certificates representing Shares of Restricted Stock in the Company’s possession until such time as all conditions and/or restrictions applicable to such Shares have been satisfied or lapse.

Except as otherwise provided in this Article 8, Shares of Restricted Stock subject to each Restricted Stock Award shall become freely transferable by the Participant after all conditions and restrictions applicable to such Shares have been satisfied or lapse (including satisfaction of any applicable tax withholding obligations), and Restricted Stock Units shall be paid in cash, Shares, or a combination of cash and Shares as the Committee, in its sole discretion, shall determine.

8.4 Certificate Legend. In addition to any legends placed on certificates pursuant to Section 8.3, each certificate representing Shares of Restricted Stock granted pursuant to this Plan may bear a legend such as the following or as otherwise determined by the Committee in its sole discretion:

THE SHARES OF STOCK REPRESENTED BY THIS CERTIFICATE ARE SUBJECT TO CERTAIN RESTRICTIONS UPON TRANSFER AND FORFEITURE OR REPURCHASE PROVISIONS SET FORTH IN THE SEMPRA ENERGY 2013 LONG-TERM INCENTIVE PLAN, AND IN THE ASSOCIATED AWARD AGREEMENT BETWEEN THE HOLDER OF THE SHARES AND SEMPRA ENERGY, A COPY OF EACH OF WHICH IS ON FILE AT THE PRINCIPAL OFFICE OF SEMPRA ENERGY.

8.5 Voting Rights. Unless otherwise determined by the Committee in its sole discretion, during the Period of Restriction, Participants holding Shares of Restricted Stock granted hereunder shall be granted the right to exercise full voting rights with respect to those Shares. A Participant shall have no voting rights with respect to any Restricted Stock Units granted hereunder.

8.6 Dividends and Other Distributions. Unless otherwise determined by the Committee in its sole discretion, during the Period of Restriction, Participants holding Shares of Restricted Stock granted hereunder shall be credited with dividends paid with respect to the underlying Shares while they are so held in a manner determined by the Committee, in its sole discretion. The Committee may apply any restrictions to the dividends that the Committee deems appropriate. The Committee, in its sole discretion, may determine the form of payment of dividends, including cash, Shares, or Restricted Stock. Notwithstanding anything to the contrary in this Section 8.6, any dividends that become payable with respect to Shares of Restricted Stock that remain subject to performance vesting conditions shall be subject to the same performance vesting conditions as apply to the underlying Shares of Restricted Stock.

8.7 Termination of Employment. Each Award Agreement shall set forth the extent to which the Participant shall have the right to retain Restricted Stock and/or Restricted Stock Units following termination of the Participant’s employment with or provision of services to the Company and/or its Subsidiaries, as the case may be. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with each Participant, need not be uniform among all Shares of Restricted Stock or Restricted Stock Units issued pursuant to this Plan, and may reflect distinctions based on the reasons for termination.

8.8 Section 83(b) Election. The Committee may provide in an Award Agreement that the Award of Restricted Stock is conditioned upon the Participant making or refraining from making an election with respect to the Award under Code Section 83(b). If a Participant makes an election pursuant to Code Section 83(b) concerning a Restricted Stock Award, the Participant shall be required to file promptly a copy of such election with the Company.

Article 9. Stock Payment Awards

9.1 Grant of Stock Payment Awards. Subject to the terms and provisions of this Plan, the Committee, at any time and from time to time, may grant Stock Payment Awards to Participants in such number of Shares as the Committee shall determine. A Stock Payment Award shall provide for: (a) the distribution of Shares to the Participant on the Grant Date; or (b) the distribution of Shares, or the payment of cash, after the Grant Date, in each case, subject to the terms and conditions of such Award. A Stock Payment Award that provides for a deferred distribution of Shares shall specify the dates or events upon which the Shares shall be distributed and such other terms and conditions as the Committee determines.

9.2 Stock Payment Award Agreement. Each Stock Payment Award shall be evidenced by an Award Agreement that shall specify the number of Shares granted, the extent to which the Participant shall have the right to retain the Stock Payment Award evidenced thereby following termination of the Participant’s employment with or provision of services to the Company and/or its Subsidiaries, and such other provisions as the Committee shall determine which are not inconsistent with the terms of this Plan.

9.3 Form and Timing of Distribution or Payment of Stock Payment Awards. Distribution of the Shares pursuant to Stock Payment Awards shall be as determined by the Committee and as evidenced in the Award Agreement. Subject to the terms of this Plan, (a) a Stock Payment Award distributed on the Grant Date shall be distributed in the form of Shares, and (b) in the case of a Stock Payment Award that is distributed or paid after the Grant Date, the Committee, in its sole discretion, may distribute or pay such Stock Payment Award in the form of cash or in Shares (or in a combination thereof); provided that any cash paid in lieu of Shares in settlement of any such Stock Payment Award (or portion thereof) shall be equal to the Fair Market Value of such Shares, as determined as of the date of payment. Any Shares issued pursuant to Stock Payment Awards may be granted subject to any restrictions deemed appropriate by the Committee.

9.4 Termination of Employment. Each Award Agreement shall set forth the extent to which the Participant shall have the right to retain the Stock Payment Award evidenced thereby following termination of the Participant’s employment with or provision of services to the Company and/or its Subsidiaries, as the case may be. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with each Participant, need not be uniform among all Stock Payment Awards issued pursuant to this Plan, and may reflect distinctions based on the reasons for termination.

9.5 Voting Rights. A Participant shall have no voting rights with respect to a Stock Payment Award granted hereunder until the Shares subject to the Award have been distributed to the Participant.

Article 10. Dividend Equivalent Awards

10.1 Grant of Dividend Equivalent Awards. Subject to the terms and provisions of this Plan, the Committee, at any time and from time to time, may grant Dividend Equivalent Awards to Participants with respect to: (a) the Shares subject to another Award, or (b) such number of Shares as the Committee shall specify. A Dividend Equivalent Award shall represent the right to receive Shares, or cash, determined based on the dividends that a Participant would have received, had the Participant held the number of Shares subject to such other Award, or the number of Shares specified by the Committee, for all or any portion of the period from the Grant Date of the Dividend Equivalent Award to the date of the exercise, vesting, distribution or expiration of such other Award, as determined by the Committee, or the date specified under the Dividend Equivalent Award, and, to the extent such Divided Equivalents are not distributed or paid currently, assuming that the dividends were reinvested in Shares (and any dividends on such Shares were reinvested in Shares) during such period. The dividends shall be deemed reinvested in Shares in the manner specified under the terms of the Award.

10.2 Dividend Equivalent Award Agreement. Each Dividend Equivalent Award shall be evidenced by an Award Agreement that shall designate the other Award to which such Dividend Equivalent Award relates, or shall specify the number of Shares with respect to which dividends shall be determined, the form of payout with respect to the Dividend Equivalent Award, the extent to which the Participant shall have the right to retain the Dividend Equivalent Award evidenced thereby following termination of the Participant’s employment with or provision of services to the Company and/or its Subsidiaries, and such other provisions as the Committee shall determine which are not inconsistent with the terms of this Plan.

10.3 Form and Timing of Distribution or Payment of Dividend Equivalent Awards. Distribution or payment of the Shares, or payment of the cash value of the Shares, earned pursuant to Dividend Equivalent Awards shall be as determined by the Committee and as evidenced in the Award Agreement. Subject to the terms of this Plan, the Committee, in its sole discretion, may determine whether the Dividend Equivalents under an Award shall be distributed or paid as dividends or Shares are paid, or distributed or paid on a deferred basis. Subject to the terms of this Plan, the Committee, in its sole discretion, may distribute or pay any earned portion of a Dividend Equivalent Award in the form of cash or in Shares (or in a combination thereof); provided that any cash paid in lieu of Shares in settlement of any Dividend Equivalent Award (or portion thereof) shall be equal to the Fair Market Value of such Shares, determined as of the date of payment. Any Shares issued pursuant to Dividend Equivalent Awards may be granted subject to any restrictions deemed appropriate by the Committee. The determination of the Committee with respect to the form of payout of such Awards shall be set forth in the Award Agreement pertaining to the grant of the Award. Notwithstanding anything to the contrary in this Section 10.3, any Dividend Equivalent Awards that are made with respect to an outstanding Award that is subject to performance vesting conditions shall vest and become payable subject to the performance vesting conditions as apply to the underlying Award.

10.4 Termination of Employment. Each Award Agreement shall set forth the extent to which the Participant shall have the right to retain the Dividend Equivalent Award evidenced thereby following termination of the Participant’s employment with or provision of services to the Company and/or its Subsidiaries, as the case may be. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with each Participant, need not be uniform among all Dividend Equivalent Awards issued pursuant to this Plan, and may reflect distinctions based on the reasons for termination.

Article 11. Cash-Based Awards

11.1 Grant of Cash-Based Awards. Subject to the terms and provisions of the Plan, the Committee, at any time and from time to time, may grant Cash-Based Awards to Participants in such dollar amounts as the Committee may determine.

11.2 Cash-Based Award Agreement. Each Cash-Based Award shall be evidenced by an Award Agreement that shall specify the payment amount or amounts, the performance goals, the Performance Period, the time and form of payment, the extent to which the Participant shall have the right to receive payment under any Cash-Based Award following termination of the Participant’s employment with or provision of services to the Company and/or its Subsidiaries, and such other provisions as the Committee shall determine which are not inconsistent with the terms of this Plan.

11.3 Value of Cash-Based Awards. Each Cash-Based Award shall specify a payment amount or amounts as determined by the Committee. The Committee may establish performance goals in its sole discretion. If the Committee exercises its discretion to establish performance goals, the value of Cash-Based Awards that will be paid out to the Participant will depend on the extent to which the performance goals are met.

11.4 Payment of Cash-Based Awards. Payment, if any, with respect to a Cash-Based Award shall be made in accordance with the terms of the Award, in cash.

11.5 Termination of Employment. The Committee shall determine the extent to which the Participant shall have the right to receive payment under any Cash-Based Award following termination of the Participant’s employment with or provision of services to the Company and/or its Subsidiaries, as the case may be. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with each Participant, need not be uniform among all Awards of Cash-Based Awards issued pursuant to the Plan, and may reflect distinctions based on the reasons for termination.

Article 12. Transferability of Awards

12.1 Transferability of Incentive Stock Options. No ISO (or Award that results in a deferral of compensation as defined in Code Section 409A) granted under this Plan may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution. Further, all ISOs granted to a Participant shall be exercisable during his or her lifetime only by such Participant.

12.2 All Other Awards. Except as otherwise provided in a Participant’s Award Agreement or otherwise determined at any time by the Committee, no Award granted under this Plan may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution; provided that the Board or Committee may permit further transferability, on a general or a specific basis, and may impose conditions and limitations on any permitted transferability, but in no event may an Award be transferred for value (as defined in the General Instructions to Form S-8 registration statement under the Securities Act of 1933, as amended from time to time). Further, except as otherwise provided in a Participant’s Award Agreement or otherwise determined at any time by the Committee, or unless the Board or Committee decides to permit further transferability, all Awards (other than ISOs) granted to a Participant under this Plan shall be exercisable during his or her lifetime only by such Participant. With respect to those Awards (other than ISOs), if any, that are permitted to be transferred to another individual, references in this Plan to exercise or payment related to such Awards by or to the Participant shall be deemed to include, as determined by the Committee, the Participant’s permitted transferee.

Article 13. Performance Measures

13.1 Performance Measures. The performance goals upon which the exercisability, vesting, distribution or payment of an Award to a Covered Employee that is intended to qualify as Performance-Based Compensation shall be limited to one or more of the following Performance Measures:

(a)

Net revenue;

(b)

Net earnings (before or after taxes);

(c)

Operating earnings or income;

(d)

Absolute and/or relative return on assets, capital, invested capital, equity, sales, or revenue;

(e)

Earnings per share;

(f)

Cash flow (including, but not limited to, operating cash flow, free cash flow, cash flow return on equity, and cash flow return on investment);

(g)

Net operating profits;

(h)

Earnings before or after any one or more of taxes, interest, depreciation, and amortization;

(i)

Earnings growth;

(j)

Gross, operating, or net margins;

(k)

Revenue growth;

(l)

Book value per share;

(m)

Stock price or shareholder return;

(n)

Economic value added;

(o)

Customer satisfaction;

(p)

Market share;

(q)

Working capital;

(r)

Productivity ratios;

(s)

Operating goals (including, but not limited to, safety, reliability, maintenance expenses, capital expenses, customer satisfaction, operating efficiency, and employee satisfaction); and

(t)

Performance relative to one or more peer companies or one or more operating units, divisions, acquired businesses, minority investments, partnerships or joint ventures thereof.

Any Performance Measure may be used to measure the performance of the Company and/or any Subsidiary, as a whole or any business unit of the Company and/or any Subsidiary, or any combination thereof, as the Committee may deem appropriate, or any of the above Performance Measures as compared to the performance of a group of comparable companies, or published or special index that the Committee, in its sole discretion, deems appropriate, or the Company may select the Performance Measures in subsection (m) above as compared to various stock market indices. The Committee also has the authority to provide for accelerated vesting of any Award based on the achievement of performance goals pursuant to the Performance Measures specified in this Article 13.

13.2 Performance Goals. The Committee shall, within the time prescribed by Code Section 162(m), designate the performance goal or goals with respect to any Award that is intended to qualify as Performance-Based Compensation. Each such performance goal shall define the objectively determinable manner of calculating the extent to which the performance goals for a Performance Period have been achieved. The Committee may provide in any Award that any performance goal may include or exclude objectively determinable adjustments, including for any one or more of the following events that occur during a Performance Period: (a) asset write-downs; (b) litigation or claim judgments or settlements; (c) the effect of changes in tax laws, accounting principles, or other laws or provisions affecting reported results; (d) any reorganization and restructuring programs; (e) extraordinary nonrecurring items as described in Financial Accounting Standards Board, Accounting Standards Codification Subtopic 225-20-45; (f) acquisitions or divestitures; and (g) foreign exchange gains and losses. To the extent such adjustments apply to the performance goals of Awards to Covered Employees, they shall be prescribed in a form and at a time that meets the requirements of Code Section 162(m) for deductibility.

13.3 Adjustment of Performance-Based Compensation. Awards that are intended to qualify as Performance-Based Compensation may not be adjusted upward. The Committee may retain the discretion to adjust such Awards downward, either on a formula or discretionary basis or any combination, as the Committee determines.

13.4 Committee Discretion. In the event that the Committee determines that it is advisable to grant Awards that shall not qualify as Performance-Based Compensation, the Committee may make such grants without satisfying the requirements of Code Section 162(m) and base vesting on Performance Measures other than those set forth in Section 13.1.

Article 14. Beneficiary Designation

Each Participant under this Plan may, from time to time, name any beneficiary or beneficiaries (who may be named contingently or successively) to whom any benefit under this Plan is to be paid in case of his death before he receives any or all of such benefit. Each such designation shall revoke all prior designations by the same Participant, shall be in a form prescribed by the Committee, and will be effective only when filed by the Participant in writing with the Company during the Participant’s lifetime. In the absence of any such beneficiary designation, benefits remaining unpaid or rights remaining unexercised at the Participant’s death shall be paid to or exercised by the Participant’s executor, administrator, or legal representative.

Article 15. Rights of Participants

15.1 Employment. Nothing in this Plan or an Award Agreement shall interfere with or limit in any way the right of the Company and/or its Subsidiaries to terminate any Participant’s employment or service on the Board or to the Company or any Subsidiary at any time or for any reason not prohibited by law, nor confer upon any Participant any right to continue his employment or service as a Director for any specified period of time.

Neither an Award nor any benefits arising under this Plan shall constitute an employment contract with the Company and/or its Subsidiaries and, accordingly, subject to Articles 3 and 16, this Plan and the benefits hereunder may be terminated at any time in the sole and exclusive discretion of the Committee without giving rise to any liability on the part of the Company and/or its Subsidiaries.

15.2 Participation. No individual shall have the right to be selected to receive an Award under this Plan, or, having been so selected, to be selected to receive a future Award.

15.3 Rights as a Shareholder. Except as otherwise provided herein, a Participant shall have none of the rights of a shareholder with respect to Shares covered by any Award until the date a certificate has been delivered to the Participant or book entries evidencing such Shares have been recorded by the Company or its transfer agent.

Article 16. Change in Control

Notwithstanding any other provision of this Plan to the contrary, the provisions of this Article 16 shall apply in the event of a Change in Control, unless otherwise determined by the Committee in connection with the grant of an Award as reflected in the applicable Award Agreement, or as provided in an individual severance or employment agreement to which a Participant is a party.

16.1 Upon a Change in Control, each then-outstanding Award may be adjusted or substituted in accordance with Section 4.4 (subject to the limitations set forth therein) with an award that meets the criteria set forth in this Section 16.1 (each, a “Replacement Award,” and each adjusted or substituted Award, a “Replaced Award”). An adjusted or substituted award meets the conditions of this Section 16.1 (and hence qualifies as a Replacement Award) if (a) it is of the same type (e.g., stock option for Option, restricted stock for Restricted Stock, restricted stock unit for Restricted Stock Unit, etc.) as the Replaced Award, (b) it has a value at least equal to the value of the Replaced Award, (c) it relates to publicly traded equity securities of the Company or its successor in the Change in Control or another entity that is affiliated with the Company or its successor following the Change in Control, (d) if the Participant holding the Replaced Award is subject to U.S. federal income tax under the Code, the tax consequences to such Participant under the Code of the Replacement Award are not less favorable to such Participant than the tax consequences of the Replaced Award, and (e) its other terms and conditions are not less favorable to the Participant holding the Replaced Award than the terms and conditions of the Replaced Award (including the provisions that would apply in the event of a subsequent Change in Control). Without limiting the generality of the foregoing, the Replacement Award may take the form of a continuation of the Replaced Award if the requirements of the preceding sentence are satisfied. The determination of whether the conditions of this Section 16.1 are satisfied will be made by the Committee, as constituted immediately before the Change in Control, in its sole discretion. Without limiting the generality of the foregoing, the Committee may determine the value of Awards and Replacement Awards that are stock options by reference to either their intrinsic value or their fair value.

16.2 In the event that a Participant does not receive a Replacement Award that meets the conditions set forth in Section 16.1 with respect to any of his or her outstanding Awards upon a Change in Control, each such outstanding Award will become fully vested and exercisable (as applicable) and any restrictions applicable to such Award will lapse, with any applicable performance goals deemed to have been achieved at the greater of target level as of the date of such vesting or the actual performance level had the performance period ended on the date of the Change in Control. For the avoidance of doubt, if all Awards hereunder are terminated without any Replacement Awards, then the Company or its successor in the Change in Control may terminate all Awards whose exercise price is less than or equal to the value per Share realized in connection with the Change in Control (without any consideration therefor).

16.3 If a Participant terminates his or her employment for Good Reason, the Participant is involuntarily terminated for reasons other than for Cause, or the Participant’s employment terminates due to the Participant’s death, Disability or Retirement during the three year period commencing on the date of a Change in Control, then (A) all Replacement Awards held by the Participant will become fully vested and, if applicable, exercisable and free of restrictions (with any applicable performance goals deemed to have been achieved at a target level as of the date of such vesting), and (B) all Options and Stock Appreciation Rights held by the Participant immediately before such termination of employment that the Participant also held as of the date of the Change in Control or that constitute Replacement Awards will remain exercisable for not less than three years following such termination of employment or until the expiration of the stated term of such Option or Stock Appreciation Rights, whichever period is shorter (provided, however, that if the applicable Award Agreement provides for a longer period of exercisability, that provision will control).

16.4 Unless a Participant is subject to a dispute resolution provision in an individual agreement (other than an Award Agreement) to which a Participant and the Company or any of its Affiliates are parties, any disagreement, dispute, controversy or claim arising out of or relating to the existence of Cause or Good Reason shall be settled pursuant to the dispute resolution provision set forth in the Participant’s applicable Award Agreement(s).

16.5 No action shall be taken under this Article 16 which shall cause an Award to fail to comply with Code Section 409A or the Treasury Regulations thereunder, to the extent applicable to such Award. In addition, if an Award is subject to Code Section 409A, Article 16 of the Plan will be applicable only to extent specifically provided in the Award Agreement and permitted pursuant to Section 20.12 of the Plan.

Article 17. Amendment, Modification, Suspension, and Termination

17.1 Amendment, Modification, Suspension, and Termination. Subject to Section 17.2, the Board or Committee may, at any time and from time to time, alter, amend, modify, suspend, or terminate this Plan and any Award Agreement in whole or in part; provided, however, that without the prior approval of the Company’s shareholders, Options or SARs granted under this Plan will not be repriced, replaced, or regranted through cancellation, or by reducing the Option Price of a previously granted Option or the SAR Grant Price of a previously granted SAR, nor will any outstanding Option or SAR having an exercise price per Share less than the then current FMV be purchased for cash or other consideration, and no amendment of this Plan shall be made without shareholder approval if (a) such amendment would increase the maximum number of Shares available for issuance to Participants under this Plan (except as otherwise permitted under Section 4.4), or (b) shareholder approval is required by law, regulation, or stock exchange rule, including, but not limited to, the Exchange Act, the Code, and if applicable, the New York Stock Exchange Listed Company Manual.

17.2 Awards Previously Granted. Notwithstanding any other provision of this Plan to the contrary (other than Section 17.3), no termination, amendment, suspension, or modification of this Plan or an Award Agreement shall adversely affect in any material way any Award previously granted under this Plan without the written consent of the Participant holding such Award.

17.3 Amendment to Conform to Law. Notwithstanding any other provision of this Plan to the contrary, the Board or the Committee may amend the Plan or an Award Agreement pursuant to the following:

(a)

The Board or the Committee may amend the Plan or an Award Agreement to take effect retroactively or otherwise, as deemed necessary or advisable for the purpose of conforming the Plan or an Award Agreement to any present or future law relating to plans of this or similar nature, and to the administrative regulations and rulings promulgated thereunder. By accepting an Award under this Plan, a Participant agrees to any amendment made pursuant to this Section 17.3 to any Award granted under the Plan without further consideration or action.

(b)

The Board or the Committee may amend the Plan or an Award Agreement to (i) exempt the Award from the requirements of Code Section 409A or preserve the intended tax treatment of the benefits provided with respect to the Award, or (ii) comply with the requirements of Section 409A of the Code and the Treasury Regulations and other interpretive guidance thereunder.

Article 18. Withholding

18.1 Tax Withholding. The Company shall have the power and the right to deduct or withhold, or require a Participant to remit to the Company, the minimum amount necessary to satisfy federal, state, local and foreign taxes required by law or regulation to be withheld with respect to any taxable event relating to an Award.

18.2 Share Withholding. With respect to withholding required upon the exercise of Options or SARs, upon the lapse of restrictions on Restricted Stock and Restricted Stock Units, or upon the achievement of performance goals related to Awards, or any other taxable event arising as a result of an Award granted hereunder, Participants may elect to satisfy the withholding requirement, in whole or in part, by having the Company withhold Shares and/or Restricted Stock Units having a Fair Market Value on the date the tax is to be determined equal to the minimum amount necessary to satisfy the federal, state, local and foreign taxes required by law or regulation to be withheld with respect to such transaction. All such elections shall be irrevocable and, with respect to elections made by any Participant other than an “officer” within the meaning of Rule 16a-1 promulgated under the Exchange Act, such elections may be subject to any restrictions or limitations that the Committee may impose.

Article 19. Successors

All obligations of the Company under this Plan with respect to Awards granted hereunder shall be binding on any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation, or otherwise, of all or substantially all of the business and/or assets of the Company.

Article 20. General Provisions

20.1 Legend. The certificates for Shares may include any legend which the Committee deems appropriate to reflect any restrictions on transfer of such Shares.

20.2 Gender and Number. Except where otherwise indicated by the context, any masculine term used herein also shall include the feminine, the plural shall include the singular, and the singular shall include the plural.

20.3 Severability. In the event any provision of this Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of this Plan, and this Plan shall be construed and enforced as if the illegal or invalid provision had not been included.

20.4 Requirements of Law. The granting of Awards and the issuance of Shares under this Plan shall be subject to all applicable laws, rules, and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.

20.5 Delivery of Title. The Company shall have no obligation to issue or deliver evidence of title for Shares issued under this Plan prior to:

(a)	Obtaining any approvals from governmental agencies that the Company determines are necessary or advisable; and

(b)	Completion of any registration or qualification of the Shares under any applicable federal, state or foreign law or ruling of any governmental body that the Company determines to be necessary or advisable.

20.6 Inability to Obtain Authority. The inability of the Company to obtain authority from any regulatory body having jurisdiction, which authority is deemed by the Company’s counsel to be necessary to the lawful issuance or sale of any Shares hereunder, shall relieve the Company of any liability in respect of the failure to issue or sell such Shares as to which such requisite authority shall not have been obtained.

20.7 Investment Representations. The Committee may require any individual receiving Shares pursuant to an Award under this Plan to represent and warrant in writing that the individual is acquiring the Shares for investment and without any present intention to sell or distribute such Shares.

20.8 Employees Based Outside of the United States. Notwithstanding any provision of this Plan to the contrary, in order to comply with the laws and/or practices in other countries in which the Company and its Subsidiaries operate or have Employees or Directors or to enact provisions desirable for administration or necessary to obtain favorable tax or accounting treatment in such other countries, the Committee, in its sole discretion, shall have the power and authority to: (i) determine which Subsidiaries shall be covered by this Plan; (ii) determine which Employees or Directors outside the United States are eligible to participate in this Plan; (iii) subject to Section 17.2, modify the terms and conditions of any Award granted to Employees or Directors outside the United States; (iv) establish subplans and modify exercise procedures, in each case with respect to Employees and Directors outside of the United States (any such subplans and/or modifications shall be attached to this Plan as appendices), provided, however, that no such subplans and/or modifications shall increase the share limitations contained in Article 4, except as otherwise permitted under Section 4.4; and (v) take any action, before or after an Award is made to an Employee or Director outside of the United States, that it deems advisable to obtain approval or comply with any necessary local governmental regulatory exemptions, approvals or practices. Notwithstanding the foregoing, the Committee may not take any actions hereunder, and no Awards shall be granted (and the Company shall have no obligation to deliver any Shares), that would violate the Exchange Act, the Code, any applicable federal, state or foreign securities law or governing statute or any other applicable law.

20.9 Uncertificated Shares. To the extent that this Plan provides for issuance of certificates to reflect the transfer of Shares, the transfer of such Shares may be effected on a noncertificated basis, to the extent not prohibited by applicable law or the rules of any stock exchange.

20.10 Unfunded Plan. Participants shall have no right, title, or interest whatsoever in or to any investments that the Company and/or its Subsidiaries may make to aid it in meeting its obligations under this Plan. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind, or a fiduciary relationship between the Company and any Participant, beneficiary, legal representative, or any other individual. To the extent that any individual acquires a right to receive payments from the Company and/or its Subsidiaries under this Plan, such right shall be no greater than the right of an unsecured general creditor of the Company or a Subsidiary, as the case may be. All payments to be made hereunder shall be paid from the general funds of the Company or a Subsidiary, as the case may be, and no special or separate fund shall be established and no segregation of assets shall be made to assure payment of such amounts.

20.11 Retirement and Welfare Plans. Neither Awards made under this Plan nor Shares or cash paid pursuant to such Awards, may be included as “compensation” for purposes of computing the benefits payable to any Participant under the Company’s or any Subsidiary’s retirement plans (both qualified and non-qualified) or welfare benefit plans unless such other plan expressly provides that such compensation shall be taken into account in computing a Participant’s benefit.

20.12 Code Section 409A. It is intended that any Award made under this Plan that results in the deferral of compensation (as defined under Code Section 409A) complies with the requirements of Code Section 409A.

(a)

To the extent applicable, the Plan and any Award Agreement shall be interpreted in accordance with Code Section 409A and the Treasury Regulations and other guidance promulgated thereunder, including, without limitation, any such regulations or other guidance that may be issued after the Effective Date. For purposes of the foregoing, with respect to any Award that results in a deferral of compensation as defined in Code Section 409A and that is subject to settlement or payment upon a Participant’s termination of employment shall be settled or paid, as applicable, only if such termination of employment qualifies as a separation from service within the meaning of Code Section 409A.

(b)

Neither a Participant nor any of a Participant’s creditors or beneficiaries will have the right to subject any Award that results in a deferral of compensation as defined in Code Section 409A to any anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, attachment, or garnishment. Except as permitted under Code Section 409A, any Award that results in a deferral of compensation as defined in Code Section 409A may not be reduced by, or offset against, any amount owing by a Participant to the Company or any of its affiliates.

(c)

If, at the time of a Participant’s separation from service (within the meaning of Code Section 409A), (i) the Participant is a specified employee (within the meaning of Code Section 409A and using the identification methodology selected by the Company from time to time) and (ii) the Company makes a good faith determination that an amount payable hereunder constitutes deferred compensation (within the meaning of Code Section 409A), the payment of which is required to be delayed pursuant to the six-month delay rule set forth in Code Section 409A in order to avoid taxes or penalties under Code Section 409A, then the Company will not pay such amount on the otherwise scheduled payment date but, unless otherwise provided in the Award Agreement, will instead pay it on the first business day of the seventh month after such separation from service.

(d)

The time or schedule of payment with respect to any Award that results in the deferral of compensation may be accelerated as permitted by Treasury Regulation Section 1.409A-3(j)(4)(ii) to the extent necessary to fulfill a domestic relations order as defined in Section 414(p)(1)(B) of the Code.

(e)

Notwithstanding any provision of the Plan and grants hereunder to the contrary, in light of the uncertainty with respect to the proper application of Code Section 409A, the Company reserves the right to make amendments to the Plan and grants hereunder as the Company deems necessary or desirable to avoid the imposition of taxes or penalties under Code Section 409A. In any case, a Participant is solely responsible and liable for the satisfaction of all taxes and penalties that may be imposed on a Participant or for a Participant’s account in connection with the Plan and grants hereunder (including any taxes and penalties under Code Section 409A), and neither the Company nor any of its affiliates have any obligation to indemnify or otherwise hold a Participant harmless from any or all of such taxes or penalties.

20.13 Nonexclusivity of this Plan. The adoption of this Plan shall not be construed as creating any limitations on the power of the Board or Committee to adopt such other compensation arrangements as it may deem desirable for any Participant.

20.14 No Constraint on Corporate Action. Nothing in this Plan shall be construed to: (a) limit, impair, or otherwise affect the Company’s or a Subsidiary’s right or power to make adjustments, reclassifications, reorganizations, or changes of its capital or business structure, or to merge or consolidate, or dissolve, liquidate, sell, or transfer all or any part of its business or assets; or (b) limit the right or power of the Company or a Subsidiary to take any action which such entity deems to be necessary or appropriate.

20.15 Governing Law; Exclusive Jurisdiction and Venue. The Plan and each Award Agreement shall be governed by the laws of the State of California, excluding any conflicts or choice of law rule or principle that might otherwise refer construction or interpretation of this Plan to the substantive law of another jurisdiction. Unless otherwise provided in the Award Agreement, recipients of an Award under this Plan are deemed to submit to the exclusive jurisdiction and venue of the federal or state courts of California, to resolve any and all issues that may arise out of or relate to this Plan or any Award Agreement.

Exhibit 10.6

SEMPRA ENERGY

2013 LONG TERM INCENTIVE PLAN

<YEAR> PERFORMANCE-BASED RESTRICTED STOCK UNIT AWARD

You have been granted a performance-based restricted stock unit award representing the right to receive the number of shares of Sempra Energy Common Stock set forth below, subject to the vesting conditions set forth below. The restricted stock units, and dividend equivalents with respect to the restricted stock units, under your award may not be sold or assigned and will be subject to forfeiture unless and until they vest based upon the satisfaction of total shareholder return performance criteria for a performance period beginning on <DATE>, <YEAR> and ending at the close of trading on <DATE>, <YEAR>. Shares of Common Stock will be distributed to you after the completion of the performance period if the restricted stock units vest under the terms and conditions of your award. The terms and conditions of your award are set forth in the attached Year <YEAR> Restricted Stock Unit Award Agreement and in the Sempra Energy 2013 Long Term Incentive Plan, which has been provided to you. The summary below highlights selected terms and conditions but it is not complete and you should carefully read the attachments to fully understand the terms and conditions of your award.
		SUMMARY

Date of Award:	<DATE>, <YEAR>
Name of Recipient:	NAME
Recipient’s Employee Number:	EE ID
Number of Restricted Stock Units (prior to any dividend equivalents):
At Target:	# RSU
At Maximum:	200% of Target (e.g. 1,000 at Target = 2,000 at Maximum)
Award Date Fair Market Value per Share of Common Stock:	$TBD
Restricted Stock Units:
Your restricted stock units represent the right to receive shares of Common Stock in the future, subject to the terms and conditions of your award. Your restricted stock units are not shares of Common Stock. The target number of restricted stock units will vest (subject to adjustment as described below), if the target total shareholder return (a return at the 50th percentile) is achieved. If above target total shareholder return is achieved, you may vest in up to the maximum number of restricted stock units plus reinvested dividends as described below.
Vesting/Forfeiture of Restricted Stock Units:
Subject to certain exceptions set forth in the Year <YEAR> Restricted Stock Unit Award Agreement, your restricted stock units will vest immediately following the Compensation Committee’s determination and certification of the extent to which Sempra Energy has met specified total shareholder return performance criteria for the performance period beginning on <DATE>, <YEAR> and ending at the close of trading on <DATE>, <YEAR>. Any restricted stock units that do not vest with the Compensation Committee's determination and certification will be forfeited.
Transfer Restrictions:
Your restricted stock units may not be sold or otherwise transferred and will remain subject to forfeiture conditions until they vest.
Termination of Employment:
Your restricted stock units also may be forfeited if your employment terminates.
Dividend Equivalents:
You also have been awarded dividend equivalents with respect to your restricted stock units. Your dividend equivalents represent the right to receive additional shares of Common Stock in the future, subject to the terms and conditions of your award. Your dividend equivalents will be determined based on the dividends that you would have received, had you held shares of Common Stock equal to the vested number of your restricted stock units from the date of your award to the date of the distribution of shares of Common Stock following the vesting of your restricted stock units, and assuming that the dividends were reinvested in Common Stock (and any dividends on such shares were reinvested in Common Stock). The dividends will be deemed reinvested in Common Stock in the same manner as dividends reinvested pursuant to the terms of the Sempra Dividend Reinvestment Plan. Your dividend equivalents will be subject to the same transfer restrictions and forfeiture and vesting conditions as the shares represented by your restricted stock units.
Distribution of Shares:
Shares of Common Stock will be distributed to you to the extent your restricted stock units vest. Except as provided otherwise in the attached Year <YEAR> Restricted Stock Unit Award Agreement, the shares will be distributed to you after the completion of the performance period ending at the close of trading on <DATE>, <YEAR> and the Compensation Committee’s determination and certification of Sempra Energy’s total shareholder return for the performance period. The shares of Common Stock will include the additional shares to be distributed pursuant to your vested dividend equivalents.
Taxes:
Upon distribution of shares of Common Stock to you, you will be subject to income taxes on the value of the distributed shares at the time of distribution and must pay applicable withholding taxes.
By your acceptance of this award, you agree to all of the terms and conditions set forth in this Cover Page/Summary, the attached Year <YEAR> Restricted Stock Unit Award Agreement and the Sempra Energy 2013 Long Term Incentive Plan.
			Recipient:	X
				(Signature)
			Sempra Energy:	/s/ Debra L. Reed
				(Signature)
			Title:	Chairman and Chief Executive Officer

SEMPRA ENERGY

2013 LONG TERM INCENTIVE PLAN

Year <YEAR> Restricted Stock Unit Award Agreement

Award:	You have been granted a performance-based restricted stock unit award under Sempra Energy’s 2013 Long Term Incentive Plan. The award consists of the number of restricted stock units set forth on the Cover Page/Summary to this Agreement, and dividend equivalents with respect to the restricted stock units (described below). Your restricted stock units represent the right to receive shares of Common Stock in the future, subject to the terms and conditions of your award. Your restricted stock units are not shares of Common Stock. Each restricted stock unit initially represents the right to receive one share of Common Stock upon the vesting of the unit. Unless and until they vest, your restricted stock units and any dividend equivalents (as described below) will be subject to transfer restrictions and forfeiture and vesting conditions. Subject to the provisions below relating to the treatment of your restricted stock units in connection with a Change in Control, your restricted stock units (and dividend equivalents) will vest immediately following and only to the extent that the Compensation Committee of Sempra Energy's Board of Directors (the “Compensation Committee”) determines and certifies that Sempra Energy has met specified total shareholder return criteria for the performance period beginning <DATE>, <YEAR> and ending at the close of trading on <DATE>, <YEAR>. Any restricted stock units (and dividend equivalents) that do not vest will be forfeited. Your restricted stock units (and dividend equivalents) also may be forfeited if your employment terminates before they vest. See “Vesting/Forfeiture,” “Transfer Restrictions,” and “Termination of Employment” below.
Vesting/Forfeiture:	Subject to the provisions below relating to the treatment of your restricted stock units in connection with a Change in Control, your restricted stock units (and dividend equivalents, as described below) will vest immediately following and only to the extent that the Compensation Committee determines and certifies that Sempra Energy has met the following total shareholder return performance criteria for the performance period beginning on <DATE>, <YEAR> and ending on the close of trading on <DATE>, <YEAR>: Preliminary Calculation Based on Sempra Energy’s cumulative total shareholder return relative to the S&P 500 Utilities Index and S&P 500 Index: § The percentage of your target number of restricted stock units that vest will be determined as follows, based on the percentile ranking for the performance period (as measured based on the thirty-day average immediately preceding the start of the performance period compared to the thirty-day average immediately preceding the end of the performance period) of Sempra Energy’s cumulative total shareholder return (consisting of per share appreciation in Common Stock plus reinvested dividends and other distributions paid on Common Stock) among the companies (ranked by cumulative total shareholder returns) in the S&P 500 Utility Index, as determined and certified by the Compensation Committee, subject to adjustment as described below. Sempra Energy Total Percentage of Target Shareholder Return Number of Restricted Percentile Ranking Stock Units that Vest 90th 200% 80th 175% 70th 150% 60th 125% 50th 100% 40th 50% 35th 25% 30th 0% If the percentile ranking does not equal a ranking shown in the above table, the percentage of your target number of restricted stock units that vest will be determined by a linear interpolation between the next lowest percentile shown in the table and the next highest percentile shown on the table, subject to adjustment as described below. o If the percentile ranking is at or above the 90th percentile, 200% of your target number of restricted stock units will vest, subject to adjustment as described below. o If the percentile ranking is at or below the 30th percentile, none of your restricted stock units will vest. · The Compensation Committee also will compare Sempra Energy’s cumulative total shareholder return for the performance period (as measured based on the thirty-day average immediately preceding the start of the performance period compared to the thirty-day average immediately preceding the end of the performance period) to the market capitalization-weighted S&P 500 Composite Index. If the Compensation Committee determines and certifies that Sempra Energy’s cumulative total shareholder return is at or above the cumulative total shareholder return of the market capitalization-weighted S&P 500 Composite Index, the percentage of your target number of restricted stock units that vest will be the greater of 100% and the percentage calculated above using the percentile ranking of Sempra Energy’s total shareholder return among companies in the S&P 500 Utility Index, subject to the adjustment described below. Final Calculation with Potential Adjustment based on Sempra Energy’s cumulative total shareholder return: · The Compensation Committee will then determine and certify the final percentage of your target restricted stock units that vest (based on the relative total shareholder return performance criteria described above) and as adjusted by the cumulative total shareholder return performance criteria described below: o If Sempra Energy’s cumulative total shareholder return for the performance period (as measured based on the thirty-day average immediately preceding the start of the performance period compared to the thirty-day average immediately preceding the end of the performance period) is at or above <PERCENTAGE>, the percentage of your restricted stock units that vest will be increased by 20%, but in no event shall the percentage of your target restricted stock unit that vest exceed 200%. o If Sempra Energy’s cumulative total shareholder return for the performance period (as measured based on the thirty-day average immediately preceding the start of the performance period compared to the thirty-day average immediately preceding the end of the performance period) is at or below <PERCENTAGE>, the percentage of your restricted stock units that vest will be decreased by 20%. o If Sempra Energy’s cumulative total shareholder return for the performance period (as measured based on the thirty-day average immediately preceding the start of the performance period compared to the thirty-day average immediately preceding the end of the performance period) is above <PERCENTAGE> but below <PERCENTAGE>, no adjustment will be applied. · As soon as reasonably practicable following the end of the performance period, the Compensation Committee will determine and certify the extent to which Sempra Energy has met the performance criteria and the extent, if any, as to which your restricted stock units have then vested and any such vesting shall occur immediately following such determination and certification by the Compensation Committee. You will receive the number of shares of Common Stock equal to the number of your vested restricted stock units after the Compensation Committee’s determination and certification. Also, you will receive the number of shares of Common Stock equal to your vested dividend equivalents after the Compensation Committee’s determination and certification. Certificates for the shares will be issued to you or transferred to an account that you designate. When the shares of Common Stock are issued to you, your restricted stock units (vested and unvested) and your dividend equivalents will terminate. · Examples illustrating the application of the vesting provisions are shown in Exhibit A to this Award Agreement.
Transfer Restrictions:	You may not sell or otherwise transfer or assign your restricted stock units (or your dividend equivalents).
Dividend Equivalents:	You also have been awarded dividend equivalents with respect to your restricted stock units. Your dividend equivalents represent the right to receive additional shares of Common Stock in the future, subject to the terms and conditions of your award. Your dividend equivalents will be determined based on the dividends that you would have received, had you held shares of Common Stock equal to the vested number of your restricted stock units from the date of your award to the date of the distribution of shares of Common Stock following the vesting of your restricted stock units, and assuming that the dividends were reinvested in Common Stock (and any dividends on such shares were reinvested in Common Stock). The dividends will be deemed reinvested in Common Stock in the same manner as dividends reinvested pursuant to the terms of the Sempra Dividend Reinvestment Plan. Your dividend equivalents will be subject to the same transfer restrictions and forfeiture and vesting conditions as your restricted stock units. They will vest when and to the extent your restricted stock units vest. Also, your restricted stock units (and dividend equivalents), including the terms and conditions thereof, will be adjusted to prevent dilution or enlargement of your rights in the event of a stock dividend on shares of Common Stock or as the result of a stock-split, recapitalization, reorganization or other similar transaction in accordance with the terms and conditions of the 2013 Long Term Incentive Plan. Any additional restricted stock units (and dividend equivalents) awarded to you as a result of such an adjustment also will be subject to the same transfer restrictions, forfeiture and vesting conditions and other terms and conditions that are applicable to your restricted stock units (and dividend equivalents).
No Shareholder Rights:	Your restricted stock units (and dividend equivalents) are not shares of Common Stock. You will have no rights as a shareholder unless and until shares of Common Stock are issued to you following the vesting of your restricted stock units (and dividend equivalents) as provided in this Agreement and the 2013 Long Term Incentive Plan.
Distribution of Shares:	As described in “Vesting/Forfeiture” above, the Compensation Committee will determine and certify the extent to which Sempra Energy has met the performance criteria and the extent, if any, as to which your restricted stock units have then vested. You will receive the number of shares of Common Stock equal to the number of your restricted stock units that have vested. However, in no event will you receive under this award, and other awards granted to you under the 2013 Long Term Incentive Plan in the same fiscal year of Sempra Energy, more than the maximum number of shares of Common Stock permitted under the 2013 Long Term Incentive Plan. Also, you will receive the number of shares of Common Stock equal to your vested dividend equivalents after the Compensation Committee’s determination and certification. You will receive the shares as soon as reasonably practicable following the Compensation Committee’s determination and certification (and in no event later than March 15, <YEAR>). Once you receive the shares of Common Stock, your vested and unvested restricted stock units (and dividend equivalents) will terminate.
Termination of Employment:
§ Termination	If your employment with Sempra Energy and its Subsidiaries terminates for any reason prior to the vesting of your restricted stock units (and dividend equivalents) (other than under the circumstances set forth in the next paragraph), all of your restricted stock units (and dividend equivalents) will be forfeited. Subject to the provisions below relating to the treatment of your restricted stock units in connection with a Change in Control, the vesting of your restricted stock units (and dividend equivalents) does not occur until the date of the Compensation Committee’s determination and certification described above. If your employment terminates prior to a Change in Control, other than by termination for cause, and you had both completed at least five years of continuous service with Sempra Energy and its Subsidiaries AND met any of the following conditions: 1.) your employment terminates after <DATE>, <YEAR> and at the date of termination you had attained age 55; or 2.) your employment terminates after <DATE>, <YEAR> and at the date of termination you had attained age 62; or 3.) at the date of termination you had attained age 65 and you were an officer subject to the company’s mandatory retirement policy; your restricted stock units (and dividend equivalents) will not be forfeited but will continue to be subject to the transfer restrictions and vesting conditions and other terms and conditions of this Agreement.
§ Termination for Cause:	If your employment with Sempra Energy and its Subsidiaries terminates for cause, or your employment would have been subject to termination for cause, prior to the vesting of your restricted stock units (and dividend equivalents), all of your restricted stock units (and dividend equivalents) will be cancelled. Prior to the consummation of a Change in Control, a termination for cause is (i) the willful failure by you to substantially perform your duties with the Company (other than any such failure resulting from your incapacity due to physical or mental illness), (ii) the grossly negligent performance of such obligations referenced in clause (i) of this definition, (iii) your gross insubordination; and/or (iv) your commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty. For purposes of clause (i), no act, or failure to act, on your part shall be deemed “willful” unless done, or omitted to be done, by you not in good faith and without reasonable belief that your act, or failure to act, was in the best interests of the Company.” If your restricted stock units remain outstanding following a Change in Control pursuant to a Replacement Award, a termination for cause following such Change in Control shall be determined in accordance with Section 2.8 of the 2013 Long Term Incentive Plan (which defines “Cause” for purposes of the plan), including reasonable notice and, if possible, a reasonable opportunity to cure as provided therein.
§ Leaves of Absence:	Your employment does not terminate when you go on military leave, a sick leave or another bona fide leave of absence, if the leave was approved by your employer in writing. But your employment will be treated as terminating 90 days after you went on leave, unless your right to return to active work is guaranteed by law or by a contract. And your employment terminates in any event when the approved leave ends, unless you immediately return to active work. Your employer determines which leaves count for this purpose.
Taxes:
§ Withholding Taxes:	When you become subject to withholding taxes upon distribution of the shares of Common Stock or otherwise, Sempra Energy or its Subsidiary is required to withhold taxes. Unless you instruct otherwise and pay or make arrangements satisfactory to Sempra Energy to pay these taxes, upon the distribution of your shares, Sempra Energy will withhold a sufficient number of shares of common stock or restricted stock units to cover the minimum required withholding taxes and transfer to you only the remaining balance of your shares. In the event that, following a Change in Control, your restricted stock units become eligible for a distribution upon your Retirement by reason of your combined age and service, your restricted stock units may become subject to employment tax withholding prior to the distribution of shares with respect to such units.
§ Code Section 409A:	Your restricted stock units are subject to Sections 16.5 and 20.12 of the 2013 Long Term Incentive Plan, which set forth terms to comply with Code Section 409A.
Recoupment (“Clawback”) Policy:	The Company shall require the forfeiture, recovery or reimbursement of awards or compensation under this Plan as (i) required by applicable law, or (ii) required under any policy implemented or maintained by the Company pursuant to any applicable rules or requirements of a national securities exchange or national securities association on which any securities of the Company are listed. The Company reserves the right to recoup compensation paid if it determines that the results on which the compensation was paid were not actually achieved. The Compensation Committee may, in its sole discretion, require the recovery or reimbursement of long-term incentive compensation awards from any employee whose fraudulent or intentional misconduct materially affects the operations or financial results of the Company or its Subsidiaries.
Retention Rights:	Neither your restricted stock unit award nor this Agreement gives you any right to be retained by Sempra Energy or any of its Subsidiaries in any capacity and your employer reserves the right to terminate your employment at any time, with or without cause. The value of your award will not be included as compensation or earnings for purposes of any other benefit plan offered by Sempra Energy or any of its Subsidiaries.
Change in Control:	In the event of a Change in Control, the following terms shall apply: § If (i) you have achieved age 55 and have completed at least five years of continuous service with Sempra Energy and its Subsidiaries as of the date of a Change in Control and your restricted stock units have not been forfeited prior to the Change in Control, (ii) your outstanding restricted stock units as of the date of a Change in Control are not subject to a “substantial risk of forfeiture” within the meaning of Code Section 409A and/or (iii) your outstanding restricted stock units are not assumed or substituted with one or more Replacement Awards as contemplated in Section 16.1 of the 2013 Long Term Incentive Plan, then in each case your outstanding restricted stock units and any associated dividend equivalents will vest immediately prior to the Change in Control with the applicable performance goals deemed to have been achieved at the greater of target level as of the date of such vesting or the actual performance level had the performance period ended on the date of the Change in Control. If the foregoing terms apply, immediately prior to the date of the Change in Control you will receive a number of shares of Common Stock equal to the number of your restricted stock units and dividend equivalents that have vested. · If your outstanding restricted stock awards are assumed or substituted with one or more Replacement Awards as contemplated in Section 16.1 of the 2013 Long Term Incentive Plan, then, except as provided otherwise in an individual severance agreement or employment agreement to which you are a party, the terms set forth in Sections 16.3 and 16.4 of the 2013 Long Term Incentive Plan shall apply with respect to such Replacement Award following the Change in Control. If the foregoing terms apply and the Replacement Award vests upon your separation from service or death, on such date, you will receive a number of shares or other property in settlement of the Replacement Awards.
Further Actions:	You agree to take all actions and execute all documents appropriate to carry out the provisions of this Agreement. You shall not be deemed to have accepted this award unless you execute the Arbitration Agreement provided with your award letter. You also appoint as your attorney-in-fact each individual who at the time of so acting is the Secretary or an Assistant Secretary of Sempra Energy with full authority to effect any transfer of any shares of Common Stock distributable to you, including any transfer to pay withholding taxes, that is authorized by this Agreement.
Applicable Law:	This Agreement will be interpreted and enforced under the laws of the State of California.
Disputes:	Any and all disputes between you and the Company relating to or arising out of the Plan or your restricted stock unit award shall be subject to the Arbitration Agreement provided with your award letter, including, but not limited to, any disputes referenced in Section 16.4 of the Plan.
Other Agreements:	In the event of any conflict between the terms of this Agreement and any written employment, severance or other employment-related agreement between you and Sempra Energy, the terms of this Agreement, or the terms of such other agreement, whichever are more favorable to you, shall prevail, provided that in each case a conflict shall be resolved in a manner consistent with the intent that your restricted stock units comply with Code Section 409A. In the event of a conflict between the terms of this Agreement and the 2013 Long Term Incentive Plan, the plan document shall prevail.

By your acceptance of this award, you agree

to all of the terms and conditions described above and in the 2013 Long Term Incentive Plan

Exhibit A

Examples Illustrating the Determination

of the Vested Percentage of the

Target Number of Restricted Stock Units

The following examples illustrate how the percentage of the target number of restricted stock units is to be determined. The examples assume that Sempra Energy achieves certain total cumulative shareholder returns for the performance period. The vested percentage of your target number of restricted stock units will be determined based on Sempra Energy’s actual cumulative total shareholder return for the performance period as measured at the end of the performance period. No assurance is given that Sempra Energy will achieve the cumulative total shareholder returns shown in the examples.

Example 1

Sempra Energy’s cumulative total shareholder return for the performance period among the companies (ranked by total shareholder returns) in the S&P 500 Utility Index, as determined and certified by the Compensation Committee, is at the 94th percentile. Sempra Energy’s cumulative total shareholder return for the performance period is <PERCENTAGE>.

Because Sempra Energy’s cumulative total cumulative shareholder return is above the 90th percentile, 200% of the target number of restricted stock units vest. This is the maximum number of restricted stock units under the award and no further award adjustment can be made even though Sempra Energy’s cumulative total shareholder return is above <PERCENTAGE>.

Example 2

Sempra Energy’s cumulative total shareholder return for the performance period among the companies (ranked by total shareholder returns) in the S&P 500 Utility Index, as determined and certified by the Compensation Committee, is at the 67th percentile and Sempra Energy’s cumulative total shareholder return for the performance period is <PERCENTAGE>.

The percentage of the target number of restricted stock units that vest is determined by a linear interpolation between the percentage based on the achievement of the 60th percentile (125%) and the percentage based on the achievement of the 70th percentile (150%).

Based on Sempra Energy’s cumulative total shareholder return relative to the S&P 500 Utilities Index and prior to consideration of the cumulative total shareholder return performance criteria,142.5% of the target number of restricted stock units would vest. Because Sempra Energy’s cumulative total shareholder return of <PERCENTAGE> is higher than <PERCENTAGE> (the trigger for the adjustment based on cumulative total shareholder return performance), the preliminary performance score is increased by 20% and the final performance score is 171%. [Calculation is 142.5% x 1.2 = 171%.]

Example 3

Sempra Energy’s cumulative total shareholder return for the performance period among the companies (ranked by total shareholder returns) in the S&P 500 Utility Index, as determined and certified by the Compensation Committee, is at the 45th percentile. Sempra Energy’s cumulative total shareholder return for the performance period is <PERCENTAGE>.

Sempra Energy’s cumulative total shareholder return for the performance period exceeds the total shareholder returns of the market capitalization-weighted S&P 500 Composite Index, as determined and certified by the Compensation Committee.

Because Sempra Energy’s cumulative total shareholder return is at the 45th percentile when ranked among the companies in the S&P 500 Utility Index, 75% of the target number of restricted stock units would vest (before taking into account Sempra Energy’s performance compared to the market capitalization-weighted S&P 500 Composite Index).

However, because Sempra Energy’s cumulative total shareholder return exceeds the total shareholder return of the market capitalization-weighted S&P 500 Composite Index, 100% of the target number of restricted stock units vest prior to consideration of the cumulative total shareholder return performance criteria. Because Sempra Energy’s cumulative total shareholder return of <PERCENTAGE> is less than <PERCENTAGE> (the trigger for the adjustment based on cumulative total shareholder return performance), the preliminary performance score is decreased by 20% and the final performance score is 80%. [Calculation is 100% x 0.80 = 80%.]

Example 4

Sempra Energy’s cumulative total shareholder return for the performance period among the companies (ranked by total shareholder returns) in the S&P 500 Utility Index, as determined and certified by the Compensation Committee, is at the 30th percentile. Sempra Energy’s cumulative total shareholder return for the performance period is <PERCENTAGE>.

Also, Sempra Energy’s total shareholder return for the performance period is below the total shareholder return of the market capitalization-weighted S&P 500 Composite Index.

Because Sempra Energy’s total shareholder return for the performance period among companies in the S&P 500 Utility Index is at the 30th percentile, none of the target number of restricted stock units vest. Because no shares vest, there is no need to determine whether any adjustment applies based on cumulative total shareholder return.

Exhibit 10.7

SEMPRA ENERGY

2013 LONG TERM INCENTIVE PLAN

<YEAR> PERFORMANCE-BASED RESTRICTED STOCK UNIT AWARD

You have been granted a performance-based restricted stock unit award representing the right to receive the number of shares of Sempra Energy Common Stock set forth below, subject to the vesting conditions set forth below. The restricted stock units, and dividend equivalents with respect to the restricted stock units, under your award may not be sold or assigned. They will be subject to forfeiture unless and until they vest based upon the satisfaction of performance criteria for a performance period beginning on January 1, <YEAR> and ending in December <YEAR>. Shares of Common Stock will be distributed to you after the completion of the performance period ending on December 31, <YEAR>, if the restricted stock units vest under the terms and conditions of your award. The terms and conditions of your award are set forth in the attached Year <YEAR> Restricted Stock Unit Award Agreement and in the Sempra Energy 2013 Long Term Incentive Plan, which has been provided to you. The summary below highlights selected terms and conditions but it is not complete and you should carefully read the attachments to fully understand the terms and conditions of your award.
	SUMMARY

Date of Award:	<DATE>, <YEAR>
Name of Recipient:	NAME
Recipient’s Employee Number:	EE ID
Number of Restricted Stock Units (prior to any dividend equivalents):
At Target:	# RSU
At Maximum:	200% of Target (e.g. 1,000 at Target = 2,000 at Maximum)
Award Date Fair Market Value per Share of Common Stock:	$TBD
Restricted Stock Units:
Your restricted stock units represent the right to receive shares of Common Stock in the future, subject to the terms and conditions of your award. Your restricted stock units are not shares of Common Stock. The target number of restricted stock units will vest (as described below), if the target “Earnings Per Share Growth” (as defined in the attached Year <YEAR> Restricted Stock Unit Award Agreement) is achieved. If above target Earnings Per Share Growth is achieved, you may vest in up to the maximum number of restricted stock units plus reinvested dividends as described below.
Vesting/Forfeiture of Restricted Stock Units:
Subject to certain exceptions set forth in the Year <YEAR> Restricted Stock Unit Award Agreement, your restricted stock units will vest immediately following the Compensation Committee’s determination and certification that Sempra Energy has achieved positive cumulative net income (to be determined in accordance with GAAP) for the performance period beginning on January 1, <YEAR> and ending December 31, <YEAR>. In such event, the percentage of restricted stock units that vest shall be a maximum of 200% of target, subject to the Compensation Committee’s exercise of negative discretion and the Compensation Committee’s determination and certification that Sempra Energy has met specified earnings per share growth criteria, as described below, for the performance period beginning on January 1, <YEAR> and ending December 31, <YEAR>. Any restricted stock units that do not vest with the Compensation Committee's determination and certification will be forfeited.
Transfer Restrictions:
Your restricted stock units may not be sold or otherwise transferred and will remain subject to forfeiture conditions until they vest.
Termination of Employment:
Your restricted stock units also may be forfeited if your employment terminates.
Dividend Equivalents:
You also have been awarded dividend equivalents with respect to your restricted stock units. Your dividend equivalents represent the right to receive additional shares of Common Stock in the future, subject to the terms and conditions of your award. Your dividend equivalents will be determined based on the dividends that you would have received, had you held shares of Common Stock equal to the vested number of your restricted stock units from the date of your award to the date of the distribution of shares of Common Stock following the vesting of your restricted stock units, and assuming that the dividends were reinvested in Common Stock (and any dividends on such shares were reinvested in Common Stock). The dividends will be deemed reinvested in Common Stock in the same manner as dividends reinvested pursuant to the terms of the Sempra Dividend Reinvestment Plan. Your dividend equivalents will be subject to the same transfer restrictions and forfeiture and vesting conditions as the shares represented by your restricted stock units.
Distribution of Shares:
Shares of Common Stock will be distributed to you to the extent your restricted stock units vest. Except as provided otherwise in the attached Year <YEAR> Restricted Stock Unit Award Agreement, the shares will be distributed to you after the completion of the performance period ending on December 31, <YEAR> and the Compensation Committee’s determination and certification of Sempra Energy’s Earnings Per Share Growth for the performance period. The shares of Common Stock will include the additional shares to be distributed pursuant to your vested dividend equivalents.
Taxes:
Upon distribution of shares of Common Stock to you, you will be subject to income taxes on the value of the distributed shares at the time of distribution and must pay applicable withholding taxes.
By your acceptance of this award, you agree to all of the terms and conditions set forth in this Cover Page/Summary, the attached Year <YEAR> Restricted Stock Unit Award Agreement and the Sempra Energy 2013 Long Term Incentive Plan.
		Recipient:	X
			(Signature)
		Sempra Energy:	/s/ Debra L. Reed
			(Signature)
		Title:	Chairman and Chief Executive Officer

SEMPRA ENERGY

2013 LONG TERM INCENTIVE PLAN

Year <YEAR> Restricted Stock Unit Award Agreement

Award:	You have been granted a performance-based restricted stock unit award under Sempra Energy’s 2013 Long Term Incentive Plan. The award consists of the number of restricted stock units set forth on the Cover Page/Summary to this Agreement, and dividend equivalents with respect to the restricted stock units (described below). Your restricted stock units represent the right to receive shares of Common Stock in the future, subject to the terms and conditions of your award. Your restricted stock units are not shares of Common Stock. Each restricted stock unit initially represents the right to receive one share of Common Stock upon the vesting of the unit. Unless and until they vest, your restricted stock units and any dividend equivalents (as described below) will be subject to transfer restrictions and forfeiture and vesting conditions. Subject to the provisions below relating to the treatment of your restricted stock units in connection with a Change in Control, your restricted stock units (and dividend equivalents) will vest immediately following and only to the extent that the Compensation Committee of Sempra Energy's Board of Directors (the “Compensation Committee”) determines and certifies that Sempra Energy has met specified positive cumulative net income and earnings per share growth performance criteria for the performance period beginning January 1, <YEAR> and ending on December 31, <YEAR>. Any restricted stock units (and dividend equivalents) that do not vest will be forfeited. Your restricted stock units (and dividend equivalents) also may be forfeited if your employment terminates before they vest. See “Vesting/Forfeiture,” “Transfer Restrictions,” and “Termination of Employment” below.
Vesting/Forfeiture:	Subject to the provisions below relating to the treatment of your restricted stock units in connection with a Change in Control, your restricted stock units (and dividend equivalents, as described below) will vest immediately following and only to the extent that Compensation Committee’s determines and certifies that Sempra Energy has achieved positive cumulative fiscal <YEAR> through fiscal <YEAR> net income (to be determined in accordance with GAAP). In such event, the percentage of restricted stock units that vest shall be a maximum of 200% of target, SUBJECT TO THE COMPENSATION COMMITTEE’S EXERCISE OF NEGATIVE DISCRETION BASED ON THE EARNINGS PER SHARE GROWTH PERFORMANCE CRITERIA DESCRIBED BELOW AND CERTIFIED BY THE COMPENSATION COMMITTEE: Earnings Per Share Growth is determined based upon the compound annual growth rate (CAGR) of Sempra Energy’s fiscal <YEAR> and fiscal <YEAR> earnings per share, subject to adjustments by the Committee in its sole discretion. For purposes of this calculation, (i) the starting point to calculate Earnings Per Share Growth shall be Sempra Energy’s <YEAR> earnings per share, (ii) the ending point to calculate Earnings Per Share Growth shall be Sempra Energy’s <YEAR> earnings per share and (iii) earnings per share shall be calculated using weighted average shares outstanding (WASO) for fiscal <YEAR> and fiscal <YEAR>, as diluted to reflect outstanding stock options and RSUs (Diluted WASO). The calculation of the Earnings component of Earnings Per Share is intended to be consistent with the calculation of the Earnings under the Sempra Energy Incentive Compensation Plans (ICP) and Executive Incentive Compensation Plans (EICP). Adjustments to Earnings are intended to be generally consistent with the adjustments applied under the ICP and EICP, but the Committee shall determine which adjustments shall apply for purposes of calculating Earnings Per Share Growth. The Committee in its sole discretion shall determine the extent to which the Earnings Per Share Growth performance criteria have been achieved. In exercising negative discretion, the percentage of your target number of restricted stock units that vest will be determined as follows: Earnings Per Share Percentage of Growth Target Number of <YEAR> - <YEAR> Restricted Stock Units That Vest <PERCENT>% 200% <PERCENT>% 150% <PERCENT>% 100% <PERCENT>% 0% If the Earnings Per Share Growth does not equal a growth rate level shown in the above table, the percentage of your target number of restricted stock units that vest will be determined by a linear interpolation between the next lowest percentage shown in the table and the next highest percentage shown on the table. o If the Earnings Per Share Growth is at or above <PERCENT>%, 200% of your target number of restricted stock units will vest. o If the Earnings Per Share Growth is at or below <PERCENT>%, none of your restricted stock units will vest. As soon as reasonably practicable following the end of the performance period, the Compensation Committee will determine and certify the extent to which Sempra Energy has met the cumulative net income performance measure and, after the application of negative discretion based on the earnings per share growth performance criteria, the extent, if any, as to which your restricted stock units have then vested and any such vesting shall occur immediately following such determination and certification by the Compensation Committee. You will receive the number of shares of Common Stock equal to the number of your vested restricted stock units after the Compensation Committee’s determination and certification. Also, you will receive the number of shares of Common Stock equal to your vested dividend equivalents after the Compensation Committee’s determination and certification. Certificates for the shares will be issued to you or transferred to an account that you designate. When the shares of Common Stock are issued to you, your restricted stock units (vested and unvested) and your dividend equivalents will terminate. Notwithstanding anything to the contrary herein, the Compensation Committee, in its sole discretion, may exercise negative discretion in determining Earnings Per Share Growth to reduce the number of restricted stock units that otherwise would vest based on achievement of the applicable performance criteria set forth herein.
Transfer Restrictions:	You may not sell or otherwise transfer or assign your restricted stock units (or your dividend equivalents).
Dividend Equivalents:	You also have been awarded dividend equivalents with respect to your restricted stock units. Your dividend equivalents represent the right to receive additional shares of Common Stock in the future, subject to the terms and conditions of your award. Your dividend equivalents will be determined based on the dividends that you would have received, had you held shares of Common Stock equal to the vested number of your restricted stock units from the date of your award to the date of the distribution of shares of Common Stock following the vesting of your restricted stock units, and assuming that the dividends were reinvested in Common Stock (and any dividends on such shares were reinvested in Common Stock). The dividends will be deemed reinvested in Common Stock in the same manner as dividends reinvested pursuant to the terms of the Sempra Dividend Reinvestment Plan. Your dividend equivalents will be subject to the same transfer restrictions and forfeiture and vesting conditions as your restricted stock units. They will vest when and to the extent that your restricted stock units vest. Also, your restricted stock units (and dividend equivalents), including the terms and conditions thereof, will be adjusted to prevent dilution or enlargement of your rights in the event of a stock dividend on shares of Common Stock or as the result of a stock-split, recapitalization, reorganization or other similar transaction in accordance with the terms and conditions of the 2013 Long Term Incentive Plan. Any additional restricted stock units (and dividend equivalents) awarded to you as a result of such an adjustment also will be subject to the same transfer restrictions, forfeiture and vesting conditions and other terms and conditions that are applicable to your restricted stock units (and dividend equivalents).
No Shareholder Rights:	Your restricted stock units (and dividend equivalents) are not shares of Common Stock. You will have no rights as a shareholder unless and until shares of Common Stock are issued to you following the vesting of your restricted stock units (and dividend equivalents) as provided in this Agreement and the 2013 Long Term Incentive Plan.
Distribution of Shares:	As described in “Vesting/Forfeiture” above, the Compensation Committee will determine and certify the extent to which Sempra Energy has met the performance criteria and the extent, if any, as to which your restricted stock units have then vested. You will receive the number of shares of Common Stock equal to the number of your restricted stock units that have vested. However, in no event will you receive under this award, and other awards granted to you under the 2013 Long Term Incentive Plan in the same fiscal year of Sempra Energy, more than the maximum number of shares of Common Stock permitted under the 2013 Long Term Incentive Plan. Also, you will receive the number of shares of Common Stock equal to your vested dividend equivalents after the Compensation Committee’s determination and certification. You will receive the shares as soon as reasonably practicable following the Compensation Committee’s determination and certification (and in no event later than March 15, <YEAR>). Once you receive the shares of Common Stock, your vested and unvested restricted stock units (and dividend equivalents) will terminate.
Termination of Employment:
Termination	If your employment with Sempra Energy and its Subsidiaries terminates for any reason prior to the vesting of your restricted stock units (and dividend equivalents) (other than under the circumstances set forth in the next paragraph), all of your restricted stock units (and dividend equivalents) will be forfeited. Subject to the provisions below relating to the treatment of your restricted stock units in connection with a Change in Control, the vesting of your restricted stock units (and dividend equivalents) does not occur until the date of the Compensation Committee’s determination and certification described above. If your employment terminates prior to a Change in Control, other than by Termination for cause, and you had both completed at least five years of continuous service with Sempra Energy and its Subsidiaries AND met any of the following conditions: 1.) your employment terminates after <DATE>, <YEAR> and at the date of termination you had attained age 55; or 2.) your employment terminates after <DATE>, <YEAR> and at the date of termination you had attained age 62; or 3.) at the date of termination you had attained age 65 and you were an officer subject to the company’s mandatory retirement policy; your restricted stock units (and dividend equivalents) will not be forfeited but will continue to be subject to the transfer restrictions and vesting conditions and other terms and conditions of this Agreement.
Termination for Cause	If your employment with Sempra Energy and its Subsidiaries terminates for cause, or your employment would have been subject to termination for cause, prior to the vesting of your restricted stock units (and dividend equivalents), all of your restricted stock units (and dividend equivalents) will be cancelled. Prior to the consummation of a Change in Control, a termination for cause is (i) the willful failure by you to substantially perform your duties with the Company (other than any such failure resulting from your incapacity due to physical or mental illness), (ii) the grossly negligent performance of such obligations referenced in clause (i) of this definition, (iii) your gross insubordination; and/or (iv) your commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty. For purposes of clause (i), no act, or failure to act, on your part shall be deemed “willful” unless done, or omitted to be done, by you not in good faith and without reasonable belief that your act, or failure to act, was in the best interests of the Company.” If your restricted stock units remain outstanding following a Change in Control pursuant to a Replacement Award, a termination for cause following such Change in Control shall be determined in accordance with Section 2.8 of the 2013 Long Term Incentive Plan (which defines “Cause” for purposes of the plan), including reasonable notice and, if possible, a reasonable opportunity to cure as provided therein.

Leaves of Absence	Your employment does not terminate when you go on military leave, a sick leave or another bona fide leave of absence, if the leave was approved by your employer in writing. But your employment will be treated as terminating 90 days after you went on leave, unless your right to return to active work is guaranteed by law or by a contract. And your employment terminates in any event when the approved leave ends, unless you immediately return to active work. Your employer determines which leaves count for this purpose.
Taxes:
Withholding Taxes	When you become subject to withholding taxes upon distribution of the shares of Common Stock or otherwise, Sempra Energy or its Subsidiary is required to withhold taxes. Unless you instruct otherwise and pay or make arrangements satisfactory to Sempra Energy to pay these taxes, upon the distribution of your shares, Sempra Energy will withhold a sufficient number of shares of common stock or restricted stock units to cover the minimum required withholding taxes and transfer to you only the remaining balance of your shares. In the event that, following a Change in Control, your restricted stock units become eligible for a distribution upon your Retirement by reason of your combined age and service, your restricted stock units may become subject to employment tax withholding prior to the distribution of shares with respect to such units.
Code Section 409A	Your restricted stock units are subject to Sections 16.5 and 20.12 of the 2013 Long Term Incentive Plan, which set forth terms to comply with Code Section 409A.
Recoupment (“Clawback”) Policy:	The Company shall require the forfeiture, recovery or reimbursement of awards or compensation under this Plan as (i) required by applicable law, or (ii) required under any policy implemented or maintained by the Company pursuant to any applicable rules or requirements of a national securities exchange or national securities association on which any securities of the Company are listed. The Company reserves the right to recoup compensation paid if it determines that the results on which the compensation was paid were not actually achieved. The Compensation Committee may, in its sole discretion, require the recovery or reimbursement of long-term incentive compensation awards from any employee whose fraudulent or intentional misconduct materially affects the operations or financial results of the Company or its Subsidiaries.
Retention Rights:	Neither your restricted stock unit award nor this Agreement gives you any right to be retained by Sempra Energy or any of its Subsidiaries in any capacity and your employer reserves the right to terminate your employment at any time, with or without cause. The value of your award will not be included as compensation or earnings for purposes of any other benefit plan offered by Sempra Energy or any of its Subsidiaries.

Change in Control:	In the event of a Change in Control, the following terms shall apply: § If (i) you have achieved age 55 and have completed at least five years of continuous service with Sempra Energy and its Subsidiaries as of the date of a Change in Control and your restricted stock units have not been forfeited prior to the Change in Control, (ii) your outstanding restricted stock units as of the date of a Change in Control are not subject to a “substantial risk of forfeiture” within the meaning of Code Section 409A and/or (iii) your outstanding restricted stock units are not assumed or substituted with one or more Replacement Awards as contemplated in Section 16.1 of the 2013 Long Term Incentive Plan, then in each case your outstanding restricted stock units and any associated dividend equivalents will vest immediately prior to the Change in Control with the applicable performance goals deemed to have been achieved at the greater of target level as of the date of such vesting or the actual performance level had the performance period ended on the last day of the calendar year immediately preceding the date of the Change in Control. If the foregoing terms apply, immediately prior to the date of the Change in Control you will receive a number of shares of Common Stock equal to the number of your restricted stock units and dividend equivalents that have vested. § If your outstanding restricted stock awards are assumed or substituted with one or more Replacement Awards as contemplated in Section 16.1 of the 2013 Long Term Incentive Plan, then, except as provided otherwise in an individual severance agreement or employment agreement to which you are a party, the terms set forth in Sections 16.3 and 16.4 of the 2013 Long Term Incentive Plan shall apply with respect to such Replacement Award following the Change in Control. If the foregoing terms apply and the Replacement Award vests upon your separation from service or death, on such date, you will receive a number of shares or other property in settlement of the Replacement Awards.
Further Actions:	You agree to take all actions and execute all documents appropriate to carry out the provisions of this Agreement. You shall not be deemed to have accepted this award unless you execute the Arbitration Agreement provided with your award letter. You also appoint as your attorney-in-fact each individual who at the time of so acting is the Secretary or an Assistant Secretary of Sempra Energy with full authority to effect any transfer of any shares of Common Stock distributable to you, including any transfer to pay withholding taxes, that is authorized by this Agreement.
Applicable Law:	This Agreement will be interpreted and enforced under the laws of the State of California.
Disputes:	Any and all disputes between you and the Company relating to or arising out of the Plan or your restricted stock unit award shall be subject to the Arbitration Agreement provided with your award letter, including, but not limited to, any disputes referenced in Section 16.4 of the Plan.
Other Agreements:	In the event of any conflict between the terms of this Agreement and any written employment, severance or other employment-related agreement between you and Sempra Energy, the terms of this Agreement, or the terms of such other agreement, whichever are more favorable to you, shall prevail, provided that in each case a conflict shall be resolved in a manner consistent with the intent that your restricted stock units comply with Code Section 409A. In the event of a conflict between the terms of this Agreement and the 2013 Long Term Incentive Plan, the plan document shall prevail.

By your acceptance of this award, you agree

to all of the terms and conditions described above and in the 2013 Long Term Incentive Plan

Exhibit 10.8

SEMPRA ENERGY

2013 LONG TERM INCENTIVE PLAN

<YEAR> RESTRICTED STOCK UNIT AWARD

You have been granted a restricted stock unit award representing the right to receive the number of shares of Sempra Energy Common Stock set forth below, subject to the vesting conditions set forth below. The restricted stock units, and dividend equivalents with respect to the restricted stock units, under your award may not be sold or assigned and will be subject to forfeiture unless and until they vest. Shares of Common Stock will be distributed to you after the completion of the service period ending on <DATE> <YEAR>, if the restricted stock units vest under the terms and conditions of your award. The terms and conditions of your award are set forth in the attached Year <YEAR> Restricted Stock Unit Award Agreement and in the Sempra Energy 2013 Long Term Incentive Plan, which is enclosed. The summary below highlights selected terms and conditions but it is not complete and you should carefully read the attachments to fully understand the terms and conditions of your award.
			SUMMARY

Date of Award:		<DATE>, <YEAR>
Name of Recipient:		NAME
Recipient’s Employee Number:		Employee ID
Number of Restricted Stock Units (prior to any dividend equivalents):		# RSU

Restricted Stock Units:
Your restricted stock units represent the right to receive shares of Common Stock in the future, subject to the terms and conditions of your award. Your restricted stock units are not shares of Common Stock.
Vesting/Forfeiture of Restricted Stock Units:
Your restricted stock units will vest subject to your continued employment by Sempra Energy or its Subsidiaries through <DATE> <YEAR>. Subject to certain exceptions set forth in the Year <YEAR> Restricted Stock Unit Award Agreement, if your employment terminates for any reason prior to <DATE> <YEAR>, your restricted stock units will be forfeited.
Transfer Restrictions:
Your restricted stock units may not be sold or otherwise transferred and will remain subject to forfeiture conditions until they vest.
Termination of Employment:
Subject to certain exceptions set forth in the Year <YEAR> Restricted Stock Unit Award Agreement, your restricted stock units will be forfeited if your employment terminates before such units vest.
Dividend Equivalents:
You also have been awarded dividend equivalents with respect to your restricted stock units. Your dividend equivalents represent the right to receive additional shares of Common Stock in the future, subject to the terms and conditions of your award. Your dividend equivalents will be determined based on the dividends that you would have received, had you held shares of Common Stock equal to the vested number of your restricted stock units from the date of your award to the date of the distribution of shares of Common Stock following the vesting of your restricted stock units, and assuming that the dividends were reinvested in Common Stock (and any dividends on such shares were reinvested in Common Stock). The dividends will be deemed reinvested in Common Stock in the same manner as dividends reinvested pursuant to the terms of the Sempra Dividend Reinvestment Plan. Your dividend equivalents will be subject to the same transfer restrictions and forfeiture and vesting conditions as the shares represented by your restricted stock units.
Distribution of Shares:
Shares of Common Stock will be distributed to you to the extent your restricted stock units vest. Except as provided otherwise in the Year <YEAR> Restricted Stock Unit Award Agreement, the shares will be distributed to you after the completion of the service period ending in <DATE> <YEAR>. The shares of Common Stock will include the additional shares to be distributed pursuant to your vested dividend equivalents.
Taxes:
Upon distribution of shares of Common Stock to you, you will be subject to income taxes on the value of the distributed shares at the time of distribution and must pay applicable withholding taxes.
By your acceptance of this award, you agree to all of the terms and conditions set forth in this Cover Page/Summary, the attached Year <YEAR> Restricted Stock Unit Award Agreement and the Sempra Energy 2013 Long Term Incentive Plan.
	Recipient:			X
				(Signature)
	Sempra Energy:			/s/ Debra L. Reed
				(Signature)
	Title:			Chairman and Chief Executive Officer

SEMPRA ENERGY

2013 LONG TERM INCENTIVE PLAN

Year <YEAR> Restricted Stock Unit Award Agreement

Award:	You have been granted a restricted stock unit award under Sempra Energy’s 2013 Long Term Incentive Plan. The award consists of the number of restricted stock units set forth on the Cover Page/Summary to this Agreement, and dividend equivalents with respect to the restricted stock units (described below). Your restricted stock units represent the right to receive shares of Common Stock in the future, subject to the terms and conditions of your award. Your restricted stock units are not shares of Common Stock. Each restricted stock unit represents the right to receive one share of Common Stock upon the vesting of the unit. Unless and until they vest, your restricted stock units and any dividend equivalents (as described below) will be subject to transfer restrictions and forfeiture and vesting conditions. Your restricted stock units (and dividend equivalents) will be forfeited if your employment terminates before they vest; provided, however, that the Compensation Committee in its sole discretion may determine to vest you in all or any portion your restricted stock units (subject to Code Section 409A requirements). See “Vesting/Forfeiture,” “Transfer Restrictions,” and “Termination of Employment” below.
Vesting/Forfeiture:	Subject to the provisions below relating to the treatment of your restricted stock units in connection with a Change in Control, your restricted stock units (and dividend equivalents, as described below) will vest on <DATE> <YEAR>, subject to your continued employment by Sempra Energy or its Subsidiaries through that date. Certificates for the shares will be issued to you or transferred to an account that you designate. When the shares of Common Stock are issued to you, your restricted stock units (vested and unvested) and your dividend equivalents will terminate.
Transfer Restrictions:	You may not sell or otherwise transfer or assign your restricted stock units (or your dividend equivalents).
Dividend Equivalents:	You also have been awarded dividend equivalents with respect to your restricted stock units. Your dividend equivalents represent the right to receive additional shares of Common Stock in the future, subject to the terms and conditions of your award. Your dividend equivalents will be determined based on the dividends that you would have received, had you held shares of Common Stock equal to the vested number of your restricted stock units from the date of your award to the date of the distribution of shares of Common Stock following the vesting of your restricted stock units, and assuming that the dividends were reinvested in Common Stock (and any dividends on such shares were reinvested in Common Stock). The dividends will be deemed reinvested in Common Stock in the same manner as dividends reinvested pursuant to the terms of the Sempra Dividend Reinvestment Plan. Your dividend equivalents will be subject to the same transfer restrictions and forfeiture and vesting conditions as your restricted stock units. They will vest when your restricted stock units vest. Also, your restricted stock units (and dividend equivalents), including the terms and conditions thereof, will be adjusted to prevent dilution or enlargement of your rights in the event of a stock dividend on shares of Common Stock or as the result of a stock-split, recapitalization, reorganization or other similar transaction in accordance with the terms and conditions of the 2013 Long Term Incentive Plan. Any additional restricted stock units (and dividend equivalents) awarded to you as a result of such an adjustment also will be subject to the same transfer restrictions, forfeiture and vesting conditions and other terms and conditions that are applicable to your restricted stock units.
No Shareholder Rights:	Your restricted stock units (and dividend equivalents) are not shares of Common Stock. You will have no rights as a shareholder unless and until shares of Common Stock are issued to you following the vesting of your restricted stock units (and dividend equivalents) as provided in this Agreement and the 2013 Long Term Incentive Plan.
Distribution of Shares:	Following the vesting of your restricted stock units, you will receive the number of shares of Common Stock equal to the number of your restricted stock units that have vested. However, in no event will you receive under this award, and other awards granted to you under the 2013 Long Term Incentive Plan in the same fiscal year of Sempra Energy, more than the maximum number of shares of Common Stock permitted under the 2013 Long Term Incentive Plan. Also, you will receive the number of shares of Common Stock equal to your vested dividend equivalents. You will receive the shares as soon as reasonably practicable following the vesting date. Once you receive the shares of Common Stock, your restricted stock units (and dividend equivalents) will terminate.
Termination of Employment:
§Termination:	If your employment with Sempra Energy and its Subsidiaries terminates for any reason prior to the vesting of your restricted stock units (and dividend equivalents) all of your restricted stock units (and dividend equivalents) will be forfeited; provided, however, that the Compensation Committee in its sole discretion may determine to vest you in all or any portion your restricted stock units (subject to Code Section 409A requirements).
§Termination for Cause:	If your employment with Sempra Energy and its Subsidiaries terminates for cause, all of your restricted stock units (and dividend equivalents) will be cancelled. Prior to the consummation of a Change in Control, a termination for cause is (i) the willful failure by you to substantially perform your duties with the Company (other than any such failure resulting from your incapacity due to physical or mental illness), (ii) the grossly negligent performance of such obligations referenced in clause (i) of this definition, (iii) your gross insubordination; and/or (iv) your commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty. For purposes of clause (i), no act, or failure to act, on your part shall be deemed “willful” unless done, or omitted to be done, by you not in good faith and without reasonable belief that your act, or failure to act, was in the best interests of the Company.” If your restricted stock units remain outstanding following a Change in Control pursuant to a Replacement Award, a termination for cause following such Change in Control shall be determined in accordance with Section 2.8 of the 2013 Long Term Incentive Plan (which defines “Cause” for purposes of the plan), including reasonable notice and, if possible, a reasonable opportunity to cure as provided therein.
§Leaves of Absence:	Your employment does not terminate when you go on military leave, a sick leave or another bona fide leave of absence, if the leave was approved by your employer in writing. But your employment will be treated as terminating 90 days after you went on leave, unless your right to return to active work is guaranteed by law or by a contract. And your employment terminates in any event when the approved leave ends, unless you immediately return to active work. Your employer determines which leaves count for this purpose.
Taxes:
§Withholding Taxes:	When you become subject to withholding taxes upon distribution of the shares of Common Stock or otherwise, Sempra Energy or its Subsidiary is required to withhold taxes. Unless you instruct otherwise and pay or make arrangements satisfactory to Sempra Energy to pay these taxes, upon the distribution of your shares, Sempra Energy will withhold a sufficient number of shares of common stock or restricted stock units to cover the minimum required withholding taxes and transfer to you only the remaining balance of your shares. In the event that, following a Change in Control, your restricted stock units become eligible for a distribution upon your Retirement by reason of your combined age and service, your restricted stock units may become subject to employment tax withholding prior to the distribution of shares with respect to such units.
§Code Section 409A: Recoupment (“Clawback”) Policy:	Your restricted stock units are subject to Sections 16.5 and 20.12 of the 2013 Long Term Incentive Plan, which set forth terms to comply with Code Section 409A. The Company shall require the forfeiture, recovery or reimbursement of awards or compensation under this Plan as (i) required by applicable law, or (ii) required under any policy implemented or maintained by the Company pursuant to any applicable rules or requirements of a national securities exchange or national securities association on which any securities of the Company are listed. The Company reserves the right to recoup compensation paid if it determines that the results on which the compensation was paid were not actually achieved. The Compensation Committee may, in its sole discretion, require the recovery or reimbursement of long-term incentive compensation awards from any employee whose fraudulent or intentional misconduct materially affects the operations or financial results of the Company or its Subsidiaries.
Retention Rights:	Neither your restricted stock unit award nor this Agreement gives you any right to be retained by Sempra Energy or any of its Subsidiaries in any capacity and your employer reserves the right to terminate your employment at any time, with or without cause. The value of your award will not be included as compensation or earnings for purposes of any other benefit plan offered by Sempra Energy or any of its Subsidiaries.
Change in Control:	In the event of a Change in Control, the following terms shall apply: If (i) you have achieved age 55 and have completed at least five years of continuous service with Sempra Energy and its Subsidiaries as of the date of a Change in Control and your restricted stock units have not been forfeited prior to the Change in Control, (ii) your outstanding restricted stock units as of the date of a Change in Control are not subject to a “substantial risk of forfeiture” within the meaning of Code Section 409A and/or (iii) your outstanding restricted stock units are not assumed or substituted with one or more Replacement Awards as contemplated in Section 16.1 of the 2013 Long Term Incentive Plan, then in each case your outstanding restricted stock units and any associated dividend equivalents will become fully vested immediately prior to the Change in Control. If the foregoing terms apply, immediately prior to the date of the Change in Control you will receive a number of shares of Common Stock equal to the number of your restricted stock units and dividend equivalents that have vested. If your outstanding restricted stock awards are assumed or substituted with one or more Replacement Awards as contemplated in Section 16.1 of the 2013 Long Term Incentive Plan, then, except as provided otherwise in an individual severance agreement or employment agreement to which you are a party, the terms set forth in Sections 16.3 and 16.4 of the 2013 Long Term Incentive Plan shall apply with respect to such Replacement Award following the Change in Control. If the foregoing terms apply and the Replacement Award vests upon your separation from service or death, on such date, you will receive a number of shares or other property in settlement of the Replacement Awards.
Further Actions:	You agree to take all actions and execute all documents appropriate to carry out the provisions of this Agreement. You shall not be deemed to have accepted this award unless you execute the Arbitration Agreement provided with your award letter. You also appoint as your attorney-in-fact each individual who at the time of so acting is the Secretary or an Assistant Secretary of Sempra Energy with full authority to effect any transfer of any shares of Common Stock distributable to you, including any transfer to pay withholding taxes, that is authorized by this Agreement.
Applicable Law:	This Agreement will be interpreted and enforced under the laws of the State of California.
Disputes: Other Agreements:	Any and all disputes between you and the Company relating to or arising out of the Plan or your restricted stock unit award shall be subject to the Arbitration Agreement provided with your award letter, including, but not limited to, any disputes referenced in Section 16.4 of the Plan. In the event of any conflict between the terms of this Agreement and any written employment, severance or other employment-related agreement between you and Sempra Energy, the terms of this Agreement, or the terms of such other agreement, whichever are more favorable to you, shall prevail, provided that in each case a conflict shall be resolved in a manner consistent with the intent that your restricted stock units comply with Code Section 409A. In the event of a conflict between the terms of this Agreement and the 2013 Long Term Incentive Plan, the plan document shall prevail.

By your acceptance of this award, you agree

to all of the terms and conditions described above and in the 2013 Long Term Incentive Plan

Exhibit 10.12

Exhibit C

SEMPRA ENERGY

2013 LONG TERM INCENTIVE PLAN

<YEAR> RESTRICTED STOCK UNIT AWARD

You have been granted a restricted stock unit award representing the right to receive the number of shares of Sempra Energy Common Stock set forth below, subject to the vesting conditions set forth below. The restricted stock units, and dividend equivalents with respect to the restricted stock units, under your award may not be sold or assigned and will be subject to forfeiture unless and until they vest. Shares of Common Stock will be distributed to you after the completion of the service period ending in <DATE>, <YEAR>, if the restricted stock units vest under the terms and conditions of your award. The terms and conditions of your award are set forth in the attached Year <YEAR> Restricted Stock Unit Award Agreement and in the Sempra Energy 2013 Long Term Incentive Plan, which is enclosed. The summary below highlights selected terms and conditions but it is not complete and you should carefully read the attachments to fully understand the terms and conditions of your award.
			SUMMARY

Date of Award:		<DATE>, <YEAR>
Name of Recipient:		NAME
Recipient’s Employee Number:		Employee ID
Number of Restricted Stock Units (prior to any dividend equivalents):		# RSU

Restricted Stock Units:
Your restricted stock units represent the right to receive shares of Common Stock in the future, subject to the terms and conditions of your award. Your restricted stock units are not shares of Common Stock.
Vesting/Forfeiture of Restricted Stock Units:
Your restricted stock units will vest subject to your continued employment by Sempra Energy or its Subsidiaries through <DATE> <YEAR>. Subject to certain exceptions set forth in the Year <YEAR> Restricted Stock Unit Award Agreement, if your employment terminates for any reason prior to <DATE> <YEAR>, your restricted stock units will be forfeited.
Transfer Restrictions:
Your restricted stock units may not be sold or otherwise transferred and will remain subject to forfeiture conditions until they vest.
Termination of Employment:
Subject to certain exceptions set forth in the Year <YEAR> Restricted Stock Unit Award Agreement, your restricted stock units will be forfeited if your employment terminates before such units vest.
Dividend Equivalents:
You also have been awarded dividend equivalents with respect to your restricted stock units. Your dividend equivalents represent the right to receive additional shares of Common Stock in the future, subject to the terms and conditions of your award. Your dividend equivalents will be determined based on the dividends that you would have received, had you held shares of Common Stock equal to the vested number of your restricted stock units from the date of your award to the date of the distribution of shares of Common Stock following the vesting of your restricted stock units, and assuming that the dividends were reinvested in Common Stock (and any dividends on such shares were reinvested in Common Stock). The dividends will be deemed reinvested in Common Stock in the same manner as dividends reinvested pursuant to the terms of the Sempra Dividend Reinvestment Plan. Your dividend equivalents will be subject to the same transfer restrictions and forfeiture and vesting conditions as the shares represented by your restricted stock units.
Distribution of Shares:
Shares of Common Stock will be distributed to you to the extent your restricted stock units vest. Except as provided otherwise in the Year <YEAR> Restricted Stock Unit Award Agreement, the shares will be distributed to you after the completion of the service period ending on <DATE> <YEAR>. The shares of Common Stock will include the additional shares to be distributed pursuant to your dividend equivalents.
Taxes:
Upon distribution of shares of Common Stock to you, you will be subject to income taxes on the value of the distributed shares at the time of distribution and must pay applicable withholding taxes.
By your acceptance of this award, you agree to all of the terms and conditions set forth in this Cover Page/Summary, the attached Year <YEAR> Restricted Stock Unit Award Agreement and the Sempra Energy 2013 Long Term Incentive Plan.

	Recipient:			X
				(Signature)
	Sempra Energy:			/s/ Debra L. Reed
				(Signature)
	Title:			Chairman and Chief Executive Officer

SEMPRA ENERGY

2013 LONG TERM INCENTIVE PLAN

Year <YEAR> Restricted Stock Unit Award Agreement

Award:	You have been granted a restricted stock unit award under Sempra Energy’s 2013 Long Term Incentive Plan. The award consists of the number of restricted stock units set forth on the Cover Page/Summary to this Agreement, and dividend equivalents with respect to the restricted stock units (described below). Your restricted stock units represent the right to receive shares of Common Stock in the future, subject to the terms and conditions of your award. Your restricted stock units are not shares of Common Stock. Each restricted stock unit represents the right to receive one share of Common Stock upon the vesting of the unit. Unless and until they vest, your restricted stock units and any dividend equivalents (as described below) will be subject to transfer restrictions and forfeiture and vesting conditions. Your restricted stock units (and dividend equivalents) will be forfeited if your employment terminates before they vest; provided, however, that the Compensation Committee in its sole discretion may determine to vest you in all or any portion your restricted stock units (subject to Code Section 409A requirements). See “Vesting/Forfeiture,” “Transfer Restrictions,” and “Termination of Employment” below.
Vesting/Forfeiture:	Subject to the provisions below relating to the treatment of your restricted stock units in connection with a Change in Control, your restricted stock units (and dividend equivalents, as described below) will vest on <DATE> <YEAR>, subject to your continued employment by Sempra Energy or its Subsidiaries through that date. Certificates for the shares will be issued to you or transferred to an account that you designate. When the shares of Common Stock are issued to you, your restricted stock units (vested and unvested) and your dividend equivalents will terminate.
Transfer Restrictions:	You may not sell or otherwise transfer or assign your restricted stock units (or your dividend equivalents).
Dividend Equivalents:	You also have been awarded dividend equivalents with respect to your restricted stock units. Your dividend equivalents represent the right to receive additional shares of Common Stock in the future, subject to the terms and conditions of your award. Your dividend equivalents will be determined based on the dividends that you would have received, had you held shares of Common Stock equal to the vested number of your restricted stock units from the date of your award to the date of the distribution of shares of Common Stock following the vesting of your restricted stock units, and assuming that the dividends were reinvested in Common Stock (and any dividends on such shares were reinvested in Common Stock). The dividends will be deemed reinvested in Common Stock in the same manner as dividends reinvested pursuant to the terms of the Sempra Dividend Reinvestment Plan. Your dividend equivalents will be subject to the same transfer restrictions and forfeiture and vesting conditions as your restricted stock units. They will vest when your restricted stock units vest. Also, your restricted stock units (and dividend equivalents), including the terms and conditions thereof, will be adjusted to prevent dilution or enlargement of your rights in the event of a stock dividend on shares of Common Stock or as the result of a stock-split, recapitalization, reorganization or other similar transaction in accordance with the terms and conditions of the 2013 Long Term Incentive Plan. Any additional restricted stock units (and dividend equivalents) awarded to you as a result of such an adjustment also will be subject to the same transfer restrictions, forfeiture and vesting conditions and other terms and conditions that are applicable to your restricted stock units.
No Shareholder Rights:	Your restricted stock units (and dividend equivalents) are not shares of Common Stock. You will have no rights as a shareholder unless and until shares of Common Stock are issued to you following the vesting of your restricted stock units (and dividend equivalents) as provided in this Agreement and the 2013 Long Term Incentive Plan.
Distribution of Shares:	Following the vesting of your restricted stock units, you will receive the number of shares of Common Stock equal to the number of your restricted stock units that have vested. However, in no event will you receive under this award, and other awards granted to you under the 2013 Long Term Incentive Plan in the same fiscal year of Sempra Energy, more than the maximum number of shares of Common Stock permitted under the 2013 Long Term Incentive Plan. Also, you will receive the number of shares of Common Stock equal to your dividend equivalents. You will receive the shares as soon as reasonably practicable following the vesting date. Once you receive the shares of Common Stock, your restricted stock units (and dividend equivalents) will terminate.
Termination of Employment:
§Termination:	If your employment with Sempra Energy and its Subsidiaries terminates for any reason prior to the vesting of your restricted stock units (and dividend equivalents) all of your restricted stock units (and dividend equivalents) will be forfeited; provided, however, that the Compensation Committee in its sole discretion may determine to vest you in all or any portion your restricted stock units (subject to Code Section 409A requirements).
§Termination for Cause:	If your employment with Sempra Energy and its Subsidiaries terminates for cause, all of your restricted stock units (and dividend equivalents) will be cancelled. Prior to the consummation of a Change in Control, a termination for cause is (i) the willful failure by you to substantially perform your duties with the Company (other than any such failure resulting from your incapacity due to physical or mental illness), (ii) the grossly negligent performance of such obligations referenced in clause (i) of this definition, (iii) your gross insubordination; and/or (iv) your commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty. For purposes of clause (i), no act, or failure to act, on your part shall be deemed “willful” unless done, or omitted to be done, by you not in good faith and without reasonable belief that your act, or failure to act, was in the best interests of the Company.” If your restricted stock units remain outstanding following a Change in Control pursuant to a Replacement Award, a termination for cause following such Change in Control shall be determined in accordance with Section 2.8 of the 2013 Long Term Incentive Plan (which defines “Cause” for purposes of the plan), including reasonable notice and, if possible, a reasonable opportunity to cure as provided therein.
§Leaves of Absence:	Your employment does not terminate when you go on military leave, a sick leave or another bona fide leave of absence, if the leave was approved by your employer in writing. But your employment will be treated as terminating 90 days after you went on leave, unless your right to return to active work is guaranteed by law or by a contract. And your employment terminates in any event when the approved leave ends, unless you immediately return to active work. Your employer determines which leaves count for this purpose.
Taxes:
§Withholding Taxes:	When you become subject to withholding taxes upon distribution of the shares of Common Stock or otherwise, Sempra Energy or its Subsidiary is required to withhold taxes. Unless you instruct otherwise and pay or make arrangements satisfactory to Sempra Energy to pay these taxes, upon the distribution of your shares, Sempra Energy will withhold a sufficient number of shares of common stock or restricted stock units (valued in each case at the distribution date fair market value) to cover the minimum required withholding taxes and transfer to you only the remaining balance of your shares. In the event that, following a Change in Control, your restricted stock units become eligible for a distribution upon your Retirement by reason of your combined age and service, your restricted stock units may become subject to employment tax withholding prior to the distribution of shares with respect to such units.
§Code Section 409A: Recoupment (“Clawback”) Policy:	Your restricted stock units are subject to Sections 16.5 and 20.12 of the 2013 Long Term Incentive Plan, which set forth terms to comply with Code Section 409A. The Company shall require the forfeiture, recovery or reimbursement of awards or compensation under this Plan as (i) required by applicable law, or (ii) required under any policy implemented or maintained by the Company pursuant to any applicable rules or requirements of a national securities exchange or national securities association on which any securities of the Company are listed. The Company reserves the right to recoup compensation paid if it determines that the results on which the compensation was paid were not actually achieved. The Compensation Committee may, in its sole discretion, require the recovery or reimbursement of long-term incentive compensation awards from any employee whose fraudulent or intentional misconduct materially affects the operations or financial results of the Company or its Subsidiaries.
Retention Rights:	Neither your restricted stock unit award nor this Agreement gives you any right to be retained by Sempra Energy or any of its Subsidiaries in any capacity and your employer reserves the right to terminate your employment at any time, with or without cause. The value of your award will not be included as compensation or earnings for purposes of any other benefit plan offered by Sempra Energy or any of its Subsidiaries.
Change in Control:	In the event of a Change in Control, the following terms shall apply: If (i) you have achieved age 55 and have completed at least five years of continuous service with Sempra Energy and its Subsidiaries as of the date of a Change in Control and your restricted stock units have not been forfeited prior to the Change in Control, (ii) your outstanding restricted stock units as of the date of a Change in Control are not subject to a “substantial risk of forfeiture” within the meaning of Code Section 409A and/or (iii) your outstanding restricted stock units are not assumed or substituted with one or more Replacement Awards as contemplated in Section 16.1 of the 2013 Long Term Incentive Plan, then in each case your outstanding restricted stock units and any associated dividend equivalents will become fully vested immediately prior to the Change in Control. If the foregoing terms apply, immediately prior to the date of the Change in Control you will receive a number of shares of Common Stock equal to the number of your restricted stock units and dividend equivalents that have vested. If your outstanding restricted stock awards are assumed or substituted with one or more Replacement Awards as contemplated in Section 16.1 of the 2013 Long Term Incentive Plan, then, except as provided otherwise in an individual severance agreement or employment agreement to which you are a party, the terms set forth in Sections 16.3 and 16.4 of the 2013 Long Term Incentive Plan shall apply with respect to such Replacement Award following the Change in Control. If the foregoing terms apply and the Replacement Award vests upon your separation from service or death, on such date, you will receive a number of shares or other property in settlement of the Replacement Awards.
Further Actions:	You agree to take all actions and execute all documents appropriate to carry out the provisions of this Agreement. You shall not be deemed to have accepted this award unless you execute the Arbitration Agreement provided with your award letter. You also appoint as your attorney-in-fact each individual who at the time of so acting is the Secretary or an Assistant Secretary of Sempra Energy with full authority to effect any transfer of any shares of Common Stock distributable to you, including any transfer to pay withholding taxes, that is authorized by this Agreement.
Applicable Law:	This Agreement will be interpreted and enforced under the laws of the State of California.
Disputes: Other Agreements:	Any and all disputes between you and the Company relating to or arising out of the Plan or your restricted stock unit award shall be subject to the Arbitration Agreement provided with your award letter, including, but not limited to, any disputes referenced in Section 16.4 of the Plan. In the event of any conflict between the terms of this Agreement and any written employment, severance or other employment-related agreement between you and Sempra Energy, the terms of this Agreement, or the terms of such other agreement, whichever are more favorable to you, shall prevail, provided that in each case a conflict shall be resolved in a manner consistent with the intent that your restricted stock units comply with Code Section 409A. In the event of a conflict between the terms of this Agreement and the 2013 Long Term Incentive Plan, the plan document shall prevail.

By your acceptance of this award, you agree

to all of the terms and conditions described above and in the 2013 Long Term Incentive Plan

Exhibit 10.19

SEMPRA ENERGY

2008 LONG TERM INCENTIVE PLAN

<YEAR> RESTRICTED STOCK UNIT AWARD

You have been granted a restricted stock unit award representing the right to receive the number of shares of Sempra Energy Common Stock set forth below, subject to the vesting conditions set forth below. The restricted stock units, and dividend equivalents with respect to the restricted stock units, under your award may not be sold or assigned and will be subject to forfeiture unless and until they vest. Shares of Common Stock will be distributed to you after the completion of the service period ending in <DATE>, if the restricted stock units vest under the terms and conditions of your award. The terms and conditions of your award are set forth in the attached Year <YEAR> Restricted Stock Unit Award Agreement and in the Sempra Energy 2008 Long Term Incentive Plan, which is enclosed. The summary below highlights selected terms and conditions but it is not complete and you should carefully read the attachments to fully understand the terms and conditions of your award.
		SUMMARY

Date of Award:	<DATE>
Name of Recipient:
Recipient’s Employee Number:
Number of Restricted Stock Units (prior to any dividend equivalents):

Restricted Stock Units:
Your restricted stock units represent the right to receive shares of Common Stock in the future, subject to the terms and conditions of your award. Your restricted stock units are not shares of Common Stock.
Vesting/Forfeiture of Restricted Stock Units:
Your restricted stock units will vest subject to your continued employment by Sempra Energy or its subsidiaries through <DATE>. If you employment terminates for any reason prior to <DATE>, your restricted stock units will be forfeited.
Transfer Restrictions:
Your restricted stock units may not be sold or otherwise transferred and will remain subject to forfeiture conditions until they vest.
Termination of Employment:
Your restricted stock units will be forfeited if your employment terminates prior to the vesting date.
Dividend Equivalents:
You also have been awarded dividend equivalents with respect to your restricted stock units. Your dividend equivalents represent the right to receive additional shares of Common Stock in the future, subject to the terms and conditions of your award. Your dividend equivalents will be determined based on the dividends that you would have received, had you held shares of Common Stock equal to the vested number of your restricted stock units from the date of your award to the date of the distribution of shares of Common Stock following the vesting of your restricted stock units, and assuming that the dividends were reinvested in Common Stock (and any dividends on such shares were reinvested in Common Stock). The dividends will be deemed reinvested in Common Stock in the same manner as dividends reinvested pursuant to the terms of the Sempra Dividend Reinvestment Plan. Your dividend equivalents will be subject to the same transfer restrictions and forfeiture and vesting conditions as the shares represented by your restricted stock units.
Distribution of Shares:
Shares of Common Stock will be distributed to you to the extent your restricted stock units vest. The shares will be distributed to you after the completion of the service period ending in <DATE>. The shares of Common Stock will include the additional shares to be distributed pursuant to your dividend equivalents.
Taxes:
Upon distribution of shares of Common Stock to you, you will be subject to income taxes on the value of the distributed shares at the time of distribution and must pay applicable withholding taxes.
By your acceptance of this award, you agree to all of the terms and conditions set forth in this Cover Page/Summary, the attached Year <YEAR> Restricted Stock Unit Award Agreement and the Sempra Energy 2008 Long Term Incentive Plan.
			Recipient:	X
				(Signature)
			Sempra Energy:	/s/ Debra L. Reed
				(Signature)
			Title:	Chairman and Chief Executive Officer

SEMPRA ENERGY

2008 LONG TERM INCENTIVE PLAN

Year <YEAR> Restricted Stock Unit Award Agreement

Award:	You have been granted a restricted stock unit award under Sempra Energy’s 2008 Long Term Incentive Plan. The award consists of the number of restricted stock units set forth on the Cover Page/Summary to this Agreement, and dividend equivalents with respect to the restricted stock units (described below). Your restricted stock units represent the right to receive shares of Common Stock in the future, subject to the terms and conditions of your award. Your restricted stock units are not shares of Common Stock. Each restricted stock unit represents the right to receive one share of Common Stock upon the vesting of the unit. Unless and until they vest, your restricted stock units and any dividend equivalents (as described below) will be subject to transfer restrictions and forfeiture and vesting conditions. Your restricted stock units (and dividend equivalents) will be forfeited if your employment terminates before they vest. See “Vesting/Forfeiture,” “Transfer Restrictions,” and “Termination of Employment” below.
Vesting/Forfeiture:	Your restricted stock units (and dividend equivalents, as described below) will vest on <DATE>, subject to your continued employment by Sempra Energy or its subsidiaries through that date. Certificates for the shares will be issued to you or transferred to an account that you designate. When the shares of Common Stock are issued to you, your restricted stock units (vested and unvested) and your dividend equivalents will terminate.
Transfer Restrictions:	You may not sell or otherwise transfer or assign your restricted stock units (or your dividend equivalents).
Dividend Equivalents:	You also have been awarded dividend equivalents with respect to your restricted stock units. Your dividend equivalents represent the right to receive additional shares of Common Stock in the future, subject to the terms and conditions of your award. Your dividend equivalents will be determined based on the dividends that you would have received, had you held shares of Common Stock equal to the vested number of your restricted stock units from the date of your award to the date of the distribution of shares of Common Stock following the vesting of your restricted stock units, and assuming that the dividends were reinvested in Common Stock (and any dividends on such shares were reinvested in Common Stock). The dividends will be deemed reinvested in Common Stock in the same manner as dividends reinvested pursuant to the terms of the Sempra Dividend Reinvestment Plan. Your dividend equivalents will be subject to the same transfer restrictions and forfeiture and vesting conditions as your restricted stock units. They will vest when your restricted stock units vest. Also, your restricted stock units (and dividend equivalents) will be adjusted to reflect stock dividends on shares of Common Stock or as the result of a stock-split, recapitalization, reorganization or other similar transaction in accordance with the terms and conditions of the 2008 Long Term Incentive Plan. Any additional restricted stock units (and dividend equivalents) awarded to you as a result of such an adjustment also will be subject to the same transfer restrictions, forfeiture and vesting conditions and other terms and conditions that are applicable to your restricted stock units.
No Shareholder Rights:	Your restricted stock units (and dividend equivalents) are not shares of Common Stock. You will have no rights as a shareholder unless and until shares of Common Stock are issued to you following the vesting of your restricted stock units (and dividend equivalents) as provided in this Agreement and the 2008 Long Term Incentive Plan.
Distribution of Shares:	Following the vesting of your restricted stock units, you will receive the number of shares of Common Stock equal to the number of your restricted stock units that have vested. However, in no event will you receive under this award, and other awards granted to you under the 2008 Long Term Incentive Plan in the same fiscal year of Sempra Energy, more than the maximum number of shares of Common Stock permitted under the 2008 Long Term Incentive Plan. Also, you will receive the number of shares of Common Stock equal to your dividend equivalents. You will receive the shares as soon as reasonably practicable following the vesting date. Once you receive the shares of Common Stock, your restricted stock units (and dividend equivalents) will terminate.
Termination of Employment:
§ Termination:	If your employment with Sempra Energy and its subsidiaries terminates for any reason prior to the vesting of your restricted stock units (and dividend equivalents) all of your restricted stock units (and dividend equivalents) will be forfeited; provided, however, that the Compensation Committee in its sole discretion may determine to vest you in all or any portion your restricted stock units.
§ Termination for Cause:	If your employment with Sempra Energy and its subsidiaries terminates for cause, all of your restricted stock units (and dividend equivalents) will be cancelled. A termination for cause is (i) the willful failure by you to substantially perform your duties with the Company (other than any such failure resulting from your incapacity due to physical or mental illness), (ii) the grossly negligent performance of such obligations referenced in clause (i) of this definition, (iii) your gross insubordination; and/or (iv) your commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty. For purposes of clause (i), no act, or failure to act, on your part shall be deemed “willful” unless done, or omitted to be done, by you not in good faith and without reasonable belief that your act, or failure to act, was in the best interests of the Company.”
§ Leaves of Absence:	Your employment does not terminate when you go on military leave, a sick leave or another bona fide leave of absence, if the leave was approved by your employer in writing. But your employment will be treated as terminating 90 days after you went on leave, unless your right to return to active work is guaranteed by law or by a contract. And your employment terminates in any event when the approved leave ends, unless you immediately return to active work. Your employer determines which leaves count for this purpose.
Taxes:	The following is a general summary of the federal income tax consequences of your Restricted Stock Unit Award. The summary may not cover your particular circumstances because it does not consider foreign, state, local or other tax laws and does not describe future changes in tax rules. You are urged to consult your tax advisor regarding the specific tax consequences applicable to you rather than relying on this general summary.
§ Generally:	You will not be subject to withholding taxes on your award until you receive shares of Common Stock following the vesting of your restricted stock units. When you receive your shares, you will realize taxable income based on the fair market value of the shares at the time you receive the shares. When you sell your shares you may also realize taxable gain (or loss) based upon the difference between the sales price and the amount that you have previously recognized as income.
§ Withholding Taxes:	When you become subject to withholding taxes upon distribution of the shares of Common Stock, Sempra Energy or its subsidiary is required to withhold taxes. Unless you instruct otherwise and pay or make arrangements satisfactory to Sempra Energy to pay these taxes, upon the distribution of your shares, Sempra Energy will withhold a sufficient number of shares of common stock or restricted stock units (valued in each case at the distribution date fair market value) to cover the minimum required withholding taxes and transfer to you only the remaining balance of your shares.
Recoupment (“Clawback”) Policy:	The Company shall require the forfeiture, recovery or reimbursement of awards or compensation under this Plan as (i) required by applicable law, or (ii) required under any policy implemented or maintained by the Company pursuant to any applicable rules or requirements of a national securities exchange or national securities association on which any securities of the Company are listed. The Company reserves the right to recoup compensation paid if it determines that the results on which the compensation was paid were not actually achieved. The Compensation Committee may, in its sole discretion, require the recovery or reimbursement of long-term incentive compensation awards from any employee whose fraudulent or intentional misconduct materially affects the operations or financial results of the Company or its subsidiaries.
Retention Rights:	Neither your restricted stock unit award nor this Agreement gives you any right to be retained by Sempra Energy or any of its subsidiaries in any capacity and your employer reserves the right to terminate your employment at any time, with or without cause. The value of your award will not be included as compensation or earnings for purposes of any other benefit plan offered by Sempra Energy or any of its subsidiaries.
Change in Control:	Subject to certain limitations set forth in the 2008 Long Term Incentive Plan, in the event of a Change in Control (as defined in the plan) of Sempra Energy, your restricted stock units (and dividend equivalents) shall fully vest. You will receive the number of shares of Common Stock equal to the number of your restricted stock units that have vested. Also, you will receive the number of shares of Common Stock equal to your dividend equivalents. You will receive the shares of Common Stock immediately prior to the date of the Change in Control. Immediately following the Change in Control, your vested and unvested restricted stock units (and dividend equivalents) will terminate.
Further Actions:	You agree to take all actions and execute all documents appropriate to carry out the provisions of this Agreement. You shall not be deemed to have accepted this award unless you execute the Arbitration Agreement provided with your award letter. You also appoint as your attorney-in-fact each individual who at the time of so acting is the Secretary or an Assistant Secretary of Sempra Energy with full authority to effect any transfer of any shares of Common Stock distributable to you, including any transfer to pay withholding taxes, that is authorized by this Agreement.
Applicable Law:	This Agreement will be interpreted and enforced under the laws of the State of California.
Other Agreements:	In the event of any conflict between the terms of this Agreement and any written employment, severance or other employment-related agreement between you and Sempra Energy, the terms of this Agreement, or the terms of such other agreement, whichever are more favorable to you, shall prevail.

By your acceptance of this award, you agree

to all of the terms and conditions described above and in the 2008 Long Term Incentive Plan

Exhibit 10.28

2009 AMENDMENT AND RESTATEMENT

OF THE

SEMPRA ENERGY

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

Table of Contents

Section 1 Definitions

Section 2 Eligibility For Benefits

2.1 Participation

2.2 Supplemental Retirement Benefit

2.3 Spouse’s Supplemental Retirement Benefit

2.4 Spouse’s Death Benefit

2.5 Supplemental Disability Benefit

2.6 Supplemental Disability Benefit

Section 3 Retirement Benefits

3.1 Amount of Supplemental Retirement Benefit

3.2 Amount of Spouse’s Supplemental Retirement Benefit

3.3 Adjustments

3.4 Payment

3.5 Conformance of Time and Form of Payment

under the Cash Balance Restoration Plan

3.6 Conformance of Time and Form of Payment

of the Cash Balance Restoration Benefit

Section 4 Cash Balance Restoration Benefits

4.1 Cash Balance Restoration Benefit

4.2 Amount of Cash Balance Restoration Benefit

4.3 Payment of Benefits

Section 5 Supplemental Preretirement Spouse’s Death Benefits

5.1 Benefit

5.2 Form of Benefit

Section 6 Supplemental Disability Benefits

6.1 Amount

6.2 Payment

Section 7 Administration

7.1 Authority of Committee

7.2 Calculation of Benefits

Section 8 Miscellaneous

8.1 Amendment, Termination or Removal of Participant

8.2 No Employment Right

8.3 Funding

8.4 Allocation of Costs

Section 9 Benefits Deferred under Deferred Compensation Plan

Section 10 Section 409A of the Code

Section 11 Claims Procedure

11.1 Claim

11.2 Claim Decision

11.3 Request for Review

11.4 Review of Decision

Section 12 Miscellaneous

12.1 Unsecured General Creditor

12.2 Restriction Against Assignment

12.3 Withholding

12.4 Governing Law

12.5 Receipt of Release

12.6 Payment on Behalf of Persons Under Incapacity

12.7 Notice

12.8 Errors and Misstatements

12.9 Pronouns and Plurality

12.10 Severability

12.11 Headings

Appendix A Early Retirement Reduction Factor

Appendix B Grandfather Benefit

This Supplemental Executive Retirement Plan provides retirement income, disability income and death benefits to key executives and their spouses under specified circumstances.

Except as provided in Appendix B, and except as to key executives who retired before July 1, 1998, this Plan shall amend, restate and supercede the Prior Plan.

The Plan was amended and restated effective as of December 5, 2005.

The Plan was amended and restated in its entirety effective as of December 31, 2008, except as otherwise provided in such amendment and restatement. Such amendment and restatement of the Plan was 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. The elections and amendments pursuant to such amendment and restatement made in accordance with the transitional relief under Internal Revenue Service Notice 2005-1, the Proposed Regulations under Section 409A of the Code and Internal Revenue Service Notices 2006-79 and 2007-86 shall be effective for the relevant periods on or before December 31, 2008.

The Plan is hereby amended and restated effective as of July 1, 2009. This amendment and restatement of the Plan provides that, effective as of July 1, 2009 (or, in the case of a Participant who becomes a Participant after July 1, 2009, effective as of such Participant’s commencement of participation in this Plan), such Participant’s Cash Balance Restoration Plan Benefit (if any) shall cease to be provided under the Cash Balance Restoration Plan and shall be transferred to and provided under this Plan. In the event that a Participant’s Cash Balance Restoration Plan Benefit (if any) is transferred to this Plan, such Cash Balance Restoration Plan Benefit shall be paid under this Plan at the time and in the form of payment provided for such Cash Balance Restoration Plan Benefit under the Cash Balance Restoration Plan, as determined immediately prior to the transfer of the Cash Balance Restoration Plan Benefit to this Plan (subject to the terms and conditions of this Plan).

SECTION 1

DEFINITIONS

1.1

“Actuarial Equivalent” means equivalent value when computed using the applicable mortality table promulgated by the IRS under Code Section 417(e)(3) as in effect on the first day of the Plan Year and the applicable interest rate promulgated by the IRS under Code Section 417(e)(3) for the November preceding the first day of the Plan Year.

1.2	“Average Bonus” means the average of the three highest annual incentive awards earned by a Participant under the Executive Incentive Plan during the Participant's last ten years of Service, determined an follows:

(a)

Annual incentive awards shall be counted whether or not deferred under the Deferred Compensation Plan.

(b)

If a Participant was designated as a participant in the Executive Incentive Plan for a year, but earned no annual incentive award during that year, the award will be counted as zero, and if the Participant did not earn three annual incentive awards during the other years during the last ten years of Service, the zero amount will be used to attain the average of the three highest annual incentive awards.

(c)

If the Participant was not designated as a participant in the Executive Incentive Plan for three full years of the last ten years of Service, the average shall be based on the number of full years the Participant was designated as a participant in the Executive Incentive Plan during the last ten years of Service.

(d)

As to a Participant in the Executive Incentive Plan who did not earn annual incentive awards during the last ten years of Service solely due to a disability which qualified him for a Basic Disability Plan Benefit, a Supplemental Disability Benefit or both, the applicable ten year period will be extended backwards for each year of such occurrence.

(e)

Prorated annual incentive awards earned under the Executive Incentive Plan will not be used in determining the average.

1.3	“Average Earnings” means the average Earnings of the highest two years of Service in the last ten years while a Participant was not receiving a Basic Disability Plan Benefit, a Supplemental Disability Benefit or both.

1.4	“Basic Disability Plan” means a disability plan maintained by Sempra Energy or a subsidiary which provides coverage for most full time employees of the plan sponsor.

1.5	“Basic Disability Plan Benefit” means the annual amount of benefit payable from the Basic Disability Plan to a Participant.

1.6	“Basic Pension Plan” means the Sempra Energy Cash Balance Plan, and where applicable by the context, the pension plan of a subsidiary of Sempra Energy.

1.7	“Basic Pension Plan Benefit” means the annual amount of benefit payable from the Basic Pension Plan to a Participant on his Retirement Date in the form of a straight life annuity without a cost-of-living feature unless one is provided under the Basic Pension Plan.

1.8

“Cash Balance Restoration Benefit” means the benefit payable to a Participant under Section 2.4 of this Plan in the form of a straight life annuity without a cost of living adjustment feature unless one is provided under Section 4 (or in such other form of payment as is prescribed under Section 4). A Participant’s Cash Balance Restoration Benefit shall be comprised of such Participant’s Pre-Section 409A Cash Balance Restoration Benefit (if any), and such Participant’s Post-Section 409A Cash Balance Restoration Benefit (if any).

1.9	“Cash Balance Restoration Plan” means the Sempra Energy Cash Balance Restoration Plan, or any other supplemental pension plan of any Employer providing essentially the same benefits for one or more Participants.

1.10

“Cash Balance Restoration Plan Benefit” means the benefit payable from the Cash Balance Restoration Plan to a Participant in the form of a straight life annuity without a cost of living adjustment feature unless one is provided under the Cash Balance Restoration Plan (or in such other form of payment as is prescribed under the Cash Balance Restoration Plan).

1.11	“Cash Balance Restoration Benefit Retirement Date” means the Participant’s “Retirement Date,” as defined in the Basic Pension Plan.

1.12	“Cash Balance Restoration Benefit Termination” means the Participant’s “Termination,” as defined in the Basic Pension Plan.

1.13	“Committee” means the Compensation Committee of the Company's Board of Directors.

1.14 “Company” means Sempra Energy.

1.15

“Deferred Compensation Plan” means the Sempra Energy 2005 Deferred Compensation Plan (with respect to deferrals of compensation earned on or after January 1, 2005), and the Sempra Energy Deferred Compensation & Excess Savings Plan (with respect to deferrals of compensation earned on or before December 31, 2004).

1.16	“Earnings” means base compensation only including any deferral under the Sempra Energy Savings Plan and the Deferred Compensation Plan.

1.17

“Employer” means the Company and any of its subsidiaries (any corporation of which 50% or more of the issued and outstanding stock having ordinary voting rights is owned directly or indirectly by the Company or any other business entity or association of which 50% or more of the outstanding equity interest is so owned) which adopt this Plan.

1.18	“Employment” means employment by the Employer, including the period during which a Participant is receiving a Basic Disability Plan Benefit, and any additional period during which a Participant is receiving a Supplemental Disability Benefit under this Plan.

1.19	“Executive Incentive Plan” means the Sempra Energy Executive Incentive Plan, or such other Plan or Plans as may be designated by the Committee from time to time.

1.20	“Lump Sum Option” means the “Lump Sum Option,” as defined in the Basic Pension Plan.

1.21	“Participant” means an employee of the Employer designated to participate in this Plan as specified in Section 2.1.

1.22 “Plan” means this Supplemental Executive Retirement Plan.

1.23

“Pre-Section 409A Cash Balance Restoration Benefit” means the portion of a Participant’s Cash Balance Restoration Benefit, if any, to which the Participant had a legally binding right, and which was earned and vested, as of December 31, 2004, determined in accordance with Section 409A of the Internal Revenue Code and Treasury Regulation Section 1.409A-6. Such Participant’s “Pre-Section 409A Cash Balance Restoration Benefit” shall be determined by the terms of the Cash Balance Restoration Plan and the Basic Pension Plan, as in effect as of October 3, 2004.

Such Participant’s “Pre-Section 409A Cash Balance Restoration Benefit” shall equal the present value of the amount to which such Participant would have been entitled under the Cash Balance Restoration Plan if such Participant voluntarily terminated services without cause on December 31, 2004, and received a payment of the benefits available from the Cash Balance Restoration Plan on the earliest possible date allowed under the Cash Balance Restoration Plan to receive a payment of benefits following the termination of services, and received the benefits in the form with maximum value. Notwithstanding the foregoing, for any subsequent taxable year of such Participant, the “Pre-Section 409A Cash Balance Restoration Benefit” shall increase to equal the present value of the benefit such Participant actually becomes entitled to, in the form and at the time actually paid, determined under the terms of the Cash Balance Restoration Plan (including applicable limits under the Code), as in effect on October 3, 2004, without regard to any further services rendered by such Participant after December 31, 2004, or any other events affecting the amount of or the entitlement to benefits (other than such Participant’s election with respect to the time or form of an available benefit). Such present value shall be computed using the applicable actuarial assumptions and methods under the Basic Pension Plan to the extent in accordance with Treasury Regulation Section 1.409A-6(a)(3)(i), or such other reasonable actuarial assumptions and methods as are permitted under Treasury Regulation Section 1.409A-6(a)(3)(i).

1.24

“Pre-Section 409A Supplemental Retirement Benefit” means the portion of a Participant’s Supplemental Retirement Benefit, if any, to which the Participant had a legally binding right, and which was earned and vested, as of December 31, 2004, determined in accordance with Section 409A of the Internal Revenue Code and Treasury Regulation Section 1.409A-6. Such Participant’s “Pre-Section 409A Supplemental Retirement Benefit” shall be determined by the terms of the Plan, the Cash Balance Restoration Plan and the Basic Pension Plan, as in effect as of October 3, 2004.

Such Participant’s “Pre-Section 409A Supplemental Retirement Benefit” shall equal the present value of the amount to which such Participant would have been entitled under the Plan if such Participant voluntarily terminated services without cause on December 31, 2004, and received a payment of the benefits available from the Plan on the earliest possible date allowed under the Plan to receive a payment of benefits following the termination of services, and received the benefits in the form with maximum value. Notwithstanding the foregoing, for any subsequent taxable year of such Participant, the “Pre-Section 409A Supplemental Retirement Benefit” shall increase to equal the present value of the benefit such Participant actually becomes entitled to, in the form and at the time actually paid, determined under the terms of the Plan (including applicable limits under the Code), as in effect on October 3, 2004, without regard to any further services rendered by such Participant after December 31, 2004, or any other events affecting the amount of or the entitlement to benefits (other than such Participant’s election with respect to the time or form of an available benefit). Such present value shall be computed using the applicable actuarial assumptions and methods under the Basic Pension Plan to the extent in accordance with Treasury Regulation Section 1.409A-6(a)(3)(i), or such other reasonable actuarial assumptions and methods as are permitted under Treasury Regulation Section 1.409A-6(a)(3)(i).

1.25

“Preretirement Spouse's Benefit” means, prior to a Participant’s Transfer Date, the benefit payable or paid under the Basic Pension Plan and Cash Balance Restoration Plan to a Surviving Spouse of a Participant who dies prior to Separation from Service and, on and after a Participant’s Transfer Date, the benefit payable or paid under the Basic Pension Plan and Section 4.3(e) to a Surviving Spouse of a Participant who dies prior to Separation from Service.

1.26	“Post-Section 409A Cash Balance Restoration Benefit” means a Participant’s Cash Balance Restoration Benefit, less such Participant’s Pre-Section 409A Cash Balance Restoration Benefit (if any).

1.27	“Post-Section 409A Supplemental Retirement Benefit” means a Participant’s Supplemental Retirement Benefit, less such Participant’s Pre-Section 409A Supplemental Retirement Benefit (if any).

1.28	“Prior Plan” shall mean the Pacific Enterprises Supplemental Retirement and Survivor Plan and the San Diego Gas and Electric Supplemental Executive Retirement Plan.

1.29	“Retirement” means the termination of such Participant's Employment with the Employer after five years of Service on or after the Participant attains age 55.

1.30	“Retirement Date” means the first day of the month following a Participant's Retirement.

1.31	“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).

1.32	“Service” means a Participant's credited service which would be used to compute retirement benefits under the Basic Pension Plan.

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

1.34

“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.

1.35	“Social Security Benefit” means the annual Primary Insurance Amount estimated to be payable to the Participant at age 65 under the Federal Social Security Act in effect at the time of the event.

1.36

“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)), from the Service Recipient for such Testing Year. 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).

1.37	“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).

1.38

“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).

1.39	“Spouse’s Death Benefit” means the benefit payable to the Surviving Spouse of a Participant under Section 5 of this Plan.

1.40	“Spouse's Supplemental Retirement Benefit” means the benefit payable to the Surviving Spouse of a Participant under Section 2.3 of this Plan after the Participant has died on or after his Retirement Date.

1.41	“Supplemental Disability Benefit” means the benefit payable to a disabled Participant under Section 2.6 of this Plan.

1.42

“Supplemental Retirement Benefit” means the benefit payable to a Participant under Section 2.2 of this Plan. A Participant’s Supplemental Retirement Benefit shall be comprised of such Participant’s Pre-Section 409A Supplemental Retirement Benefit (if any) and such Participant’s Post-Section 409A Supplemental Retirement Benefit (if any).

1.43

“Surviving Spouse” means in the case of a Spouse's Death Benefit, a spouse married to the Participant for at least the one-year period ending on the Participant's date of death, and means in the case of a Spouse's Supplemental Retirement Benefit, a spouse who is married to the Participant for at least the one-year period ending on the Participant's Retirement Date and who is still married to the Participant on the date of the Participant's death. Surviving Spouse also means a Spousal Equivalent as defined by the Company (subject to the one-year requirements) under the Company Medical Plan.

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

1.45	“Transfer Date” with respect to a Participant means July 1, 2009 or, if later, the date on which a Participant becomes a Participant in this Plan.

1.46	“Vesting Factor” means the following for a Participant who qualifies for Retirement under paragraph 1.29.

Vesting Schedule

		AGE
			55	56	57	58	59	60 or older
YEARS OF SERVICE	5		50%	60%	70%	80%	90%	100%
	6		55%	60%	70%	80%	90%	100%
	7		60%	65%	70%	80%	90%	100%
	8		65%	70%	75%	80%	90%	100%
	9		70%	75%	80%	85%	90%	100%
	10		75%	80%	85%	90%	95%	100%
	11		80%	85%	90%	95%	100%	100%
	12		85%	90%	95%	100%	100%	100%
	13		90%	95%	100%	100%	100%	100%
	14		95%	100%	100%	100%	100%	100%
	15 or more		100%	100%	100%	100%	100%	100%

Based on attained age and completed years of service.

1.47

“Voluntary Disability Insurance Program” means the program offered by Sempra Energy under which certain employees of Sempra Energy or a subsidiary may purchase supplemental long term disability insurance coverage, such supplemental coverage shall be voluntary and the cost of such coverage shall be paid by the employee.

1.48	“Voluntary Disability Benefit” means the annual amount of benefit payable from the supplemental long term disability insurance coverage (if any) purchased by a Participant under the Voluntary Disability Insurance Program and maintained by such Participant.

The masculine pronoun whenever used shall include the feminine pronoun, and the singular shall include the plural where the context requires it.

SECTION 2

ELIGIBILITY FOR BENEFITS

2.1 Participation

Executive Officers of the Company as designated shall be eligible to participate in this Plan. The Committee may designate additional officers and key employees of the Employer who shall participate in this Plan and the effective date of such participation, subject to agreement by the Board of Directors of the executive's Employer (if not the Company) that such executive participate and that such Employer pay the costs of this Plan for the executive and his Surviving Spouse.

2.2 Supplemental Retirement Benefit

Each Participant is eligible to retire and receive a benefit under this Plan as specified in Sections 3.1 and 3.4 beginning on his Retirement Date. No Supplemental Retirement Benefit will be paid to a Participant who leaves Employment prior to attaining age 55 or completing five years of Service, except as provided under other agreements.

2.3 Spouse's Supplemental Retirement Benefit

The Surviving Spouse of a Participant who dies on or after his Retirement Date who did not receive a lump sum payment is eligible for a Spouse's Supplemental Retirement Benefit in accordance with Sections 3.2 and 3.4.

2.4 Cash Balance Restoration Benefit

Each Participant is eligible to receive a benefit under this Plan as specified in Section 4 on and after his Transfer Date.

2.5 Spouse's Death Benefit

The Surviving Spouse of a Participant who dies in Employment is eligible for a Spouse's Death Benefit as specified in Sections 5.1 and 5.2 in the form of a lump sum benefit. There is no cost to the Participant for this benefit. If a Participant dies during Employment without an eligible Surviving Spouse, no Spouse's Death Benefit is payable under this Plan.

2.6 Supplemental Disability Benefit

A Participant who becomes disabled may be eligible to receive a Supplemental Disability Benefit as specified in Section 6.

SECTION 3

RETIREMENT BENEFITS

3.1 Amount of Supplemental Retirement Benefit

The Supplemental Retirement Benefit payable to a Participant shall be determined as of his Retirement Date and shall equal to (a) minus (b) with the resultant product multiplied by the Participant’s Vesting Factor and then the resultant product multiplied by the early retirement reduction (pursuant to Appendix A) for Retirement Dates which precede attainment of 62 years of age.

(a)

is a lump sum using the actuarial and mortality assumptions in the Basic Pension Plan based upon the single annuity value of the annual annuity with the annual annuity determined as follows: the sum of the following percent of the total of the Participant's Average Earnings and Average Bonus

(i)	1/3% for each month of Service through 120 (40% for 10 years of Service), plus

(ii)	1/6% for each month of Service in excess of 120, through 240 (60% for 20 years

of Service), plus

(iii)

1/48% for each month of Service in excess of 240 (65% for 40 years of Service).

(b)

is a lump sum using the actuarial and mortality assumptions in the Basic Pension Plan based on the single annuity value of the annual annuity with the annual annuity determined as the sum of

(i) his Basic Pension Plan Benefit, plus

(ii)

(A)

on and after such Participant’s Transfer Date, his Cash Balance Restoration Benefit in an annual amount of benefit payable to such Participant on his Retirement Date or the date of his Separation from Service, as applicable, in the form of a straight life annuity without a cost of living adjustment feature unless one is provided under Section 4, or the annual amount of benefit that would have been payable under Section 4 to such Participant on his Retirement Date or the date of his Separation from Service, as applicable, at such time and in such form, if Section 4 provided for such time and form of payment to the Participant, or

(B)

prior to such Participant’s Transfer Date, his Cash Balance Restoration Plan Benefit in an annual amount of benefit payable to such Participant on his Retirement Date or the date of his Separation from Service, as applicable, in the form of a straight life annuity without a cost of living adjustment feature unless one is provided under the Cash Balance Restoration Plan, or the annual amount of benefit that would have been payable under the Cash Balance Restoration Plan to such Participant on his Retirement Date or the date of his Separation from Service, as applicable, at such time and in such form, if the Cash Balance Restoration Plan provided for such time and form of payment to the Participant;

provided, however, that, if a Participant’s Retirement Date occurs on a different date than the date the Participant commences receipt of benefits under the Basic Pension Plan, paragraph (i) shall be calculated based on the benefits the Participant would have received if the Participant had commenced receipt of benefits under the Basic Pension Plan on the Participant’s Retirement Date.

If (a) minus (b) results in zero or less, then no Supplemental Retirement Benefit is payable.

(c)

The Participant’s Pre-Section 409A Supplemental Retirement Benefit (if any) shall be payable as of such Participant’s Retirement Date, and the Participant’s Post-Section 409A Supplemental Retirement Benefit shall be payable upon such Participant’s Separation from Service, in accordance with Section 3.4. Except as provided in paragraph (i) or (ii) below, the Participant’s Supplemental Retirement Benefit shall be paid in a lump sum.

(i)

(A)

The Participant may elect to receive the Pre-Section 409A Supplemental Retirement Benefit, payable on his behalf, paid in an actuarially equivalent annuity, provided the Participant elects the annuity one year prior to Retirement. The initial election of benefit form shall be made at the time of commencement of participation, or as soon thereafter as is reasonably practicable.

(B)

Notwithstanding the foregoing, in no event shall a distribution option be available or apply to a Participant’s Pre-Section 409A Supplemental Retirement Benefit if such distribution option would result in a material modification of the Participant’s Pre-Section 409A Supplemental Retirement Benefit, as determined under Section 409A of the Code and Treasury Regulation Section 1.409A-6.

(ii)

Prior to a Participant’s Transfer Date:

(A)

the payment of the Participant’s Post-Section 409A Supplemental Retirement Benefit shall be made or commence on the date of the payment or commencement of such Participant’s “Post-Section 409A Benefit” (as defined in the Cash Balance Restoration Plan) under the Cash Balance Restoration Plan, and the form of payment of the Participant’s Post-Section 409A Supplemental Retirement Benefit shall be the same as the form of payment of such Participant’s “Post-Section 409A Benefit” under the Cash Balance Restoration Plan, as determined in subparagraph (B). In the event that the payment of the Participant’s Post-Section 409A Supplemental Retirement Benefit is in the form of an annuity, such annuity shall be actuarially equivalent to the Participant’s Post-Section 409A Supplemental Retirement Benefit.

(B)

The payment of such Participant’s “Post-Section 409A Benefit” under the Cash Balance Restoration Plan shall be in a lump sum upon the Participant’s Separation from Service, unless the Participant elects to receive an optional annuity form of payment under the Cash Balance Restoration Plan.

(I)

In the case of a Participant who first became an “Eligible Employee” in the Cash Balance Restoration Plan on or before December 31, 2005, the Participant may elect, in writing, payment of such Participant’s “Post-Section 409A Benefit” under the Cash Balance Restoration Plan commencing upon the Participant’s Separation from Service under any of the following annuity options: (x) a straight life annuity, (y) a joint and 50% survivor annuity, and (z) a joint and 100% survivor annuity. The election will be subject to approval of the Company's Senior Human Resources Officer, in his or her discretion, and, if approved, will become effective and irrevocable on the date of such approval (except as provided in the Cash Balance Restoration Plan).

(II)

Such a Participant’s election under the Cash Balance Restoration Plan may be made with respect to such Participant’s “Post-Section 409A Benefit” on or after January 1, 2006 and on or before December 31, 2008 in accordance with the transitional relief under Section 409A of the Internal Revenue Code and Internal Revenue Service Notices 2006-79 and 2007-86; provided, however, that such Participant’s election made in 2006 shall only apply with respect to payments that would not otherwise be payable in 2006, and shall not cause payments to be made in 2006 that would not otherwise be payable in 2006; and, provided, further, that such Participant’s election made in 2007 shall apply only with respect to payments that would not otherwise be payable in 2007 and shall not cause payments to be made in 2007 that would not otherwise be payable in 2007; and, provided, further, that such Participant’s election made in 2008 shall apply only with respect to payments that would not otherwise be payable in 2008 and shall not cause payments to be made in 2008 that would not otherwise be payable in 2008. A Participant’s election under this clause (II) shall be considered made when the election becomes irrevocable. No such payment election may be made by such Participant unless such election becomes irrevocable on or prior to December 31, 2008.

(III)

The joint and survivor annuity is only available under clause (I)(y) or (z) if the Participant designates his or her spouse as beneficiary or obtains spousal consent to the designation of another beneficiary in the same manner as under the Basic Pension Plan as part of the Participant’s election. If the spouse, or beneficiary dies before the Participant’s Separation from Service, the joint and survivor annuity is canceled and the benefit is paid in the form of a straight life annuity; provided, that the straight life annuity is actuarially equivalent, applying reasonable actuarial methods and assumptions, to the joint and survivor annuity in effect prior to such cancellation, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(IV)

Except as provided in subsection (C), such Participant may not change the form and time of payment of such Participant’s “Post-Section 409A Benefit” under the Cash Balance Restoration Plan after December 31, 2008.

(v)

A lump sum payment of a Participant’s Post-Section 409A Supplemental Retirement Benefit under this subparagraph (A) shall be paid on such date as is determined by Sempra Energy within thirty (30) days following the Participant’s Separation from Service. If an annuity payment is elected, for purposes of the payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit under this subparagraph (A), such Post-Section 409A Supplemental Retirement Benefit shall be paid monthly, beginning on the last day of the month of the Participant’s Separation from Service and will continue to be paid monthly during the life of the Participant and the life of the Participant’s beneficiary, if any (if such beneficiary survives the Participant). In all cases, the monthly benefit shall equal the annual benefit divided by 12.

(C)

(I)

In the event that such Participant elects to change the form of the payment of such Participant’s “Post-Section 409A Benefit” (as defined in the Cash Balance Restoration Plan) under the Cash Balance Restoration Plan, such Participant shall be deemed to have elected to change the form of the payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit to the form of the payment of such Participant’s “Post-Section 409A Benefit” under the Cash Balance Restoration Plan. The Participant’s election shall be subject to clauses (II), (III), (IV), (V), (VI) and (VII). Except as provided in clauses (VI), the Participant’s election under this clause (I) shall be irrevocable.

(II)

The Participant’s election under clause (I) must be made prior to the Participant’s Separation from Service.

(III)

If the Participant’s form of payment, as in effect at the time of election under clause (I), is an annuity, such Participant’s election of an alternative annuity form of payment shall be effective immediately and clause (V) shall not apply to such Participant’s election; provided, that the alternative annuity form of payment elected by the Participant is actuarially equivalent applying reasonable actuarial methods and assumptions to the annuity form of payment, as in effect at the time of the election, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(IV)

Except as provided in clause (III), the Participant’s election under clause (I) shall not take effect until 12 months after his election is made in accordance with Treasury Regulation Section 1.409A-2(b)(1)(i). If the Participant has a Separation from Service before the election under clause (I) becomes effective, the election under clause (I) shall terminate and the Participant’s Post-Section 409A Supplemental Retirement Benefit shall be paid in the form of payment as in effect at the time of the election under clause (I).

(V)

Except as provided in clause (III), in the event the Participant’s election under clause (I) becomes effective, the payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit under the option shall be deferred for a period of five years from the date such payment would otherwise have been paid (or, in the case of a life annuity treated as a single payment, five years from the date the first amount was scheduled to be paid), in accordance with Treasury Regulation Section 1.409A-2(b)(1)(ii).

(VI)

In the event that the form of payment of such Participant’s “Post-Section 409A Benefit” (as defined in the Cash Balance Restoration Plan) under the Cash Balance Restoration Plan is an annuity, and such Participant elects to change the form of payment of such Participant’s “Post-Section 409A Benefit” to another annuity option, the Participant shall be deemed to have elected to change the annuity option elected under clause (I) to the annuity option of the payment of such Participant’s “Post-Section 409A Benefit” and such election shall become effective immediately, provided, that such change is made prior to the commencement of the payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit under this Plan; and, provided, further, that the annuity form of payment is actuarially equivalent to the annuity form of payment, as in effect at the time of the election, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(VII)

Any change in a Participant’s form of payment under this subparagraph (B) shall be made in accordance with Treasury Regulation Section 1.409A-2(b).

(D)

On and after a Participant’s Transfer Date, the payment of the Participant’s Post-Section 409A Supplemental Retirement Benefit shall be made in accordance with Section 3.6.

(d)

Conformance with Treasury Regulations

The benefits payable under this Section 3.1 are determined as an amount offset by the benefits provided under the Basic Pension Plan. The benefits payable under this Plan shall be determined in a manner consistent with Treasury Regulation Sections 1.409A-2(a)(9) and 1.409A-3(j)(5) (relating to nonqualified deferred compensation plans linked to qualified employer plans). Any amendment of the Basic Pension Plan shall be taken into account under this Plan only to the extent permitted under Treasury Regulation Sections 1.409A-2(a)(9) and 1.409A-3(j)(5). Any reference to the interest and mortality factors (or actuarial methods and assumptions) specified in the Basic Pension Plan shall mean the applicable interest and mortality factors (or actuarial methods or assumptions) specified under the terms of the Basic Pension Plan, determined based on the terms in effect on December 31, 2008.

3.2	Amount of Spouse's Supplemental Retirement Benefit

The annual Spouse's Supplemental Retirement Benefit payable to a Surviving Spouse of a Participant who did not receive a lump sum payment is equal to 50% of the Participant's Supplemental Retirement Benefit as determined in accordance with in Section 3.1(a) without the reduction in 3.1(b) but adjusted by the Vesting Factor and the early retirement reduction pursuant to appendix A. The Spouse’s Supplemental Retirement Benefit shall be paid monthly, beginning on the last day of the month next following the month in which the death of the Participant occurs and will continue to be paid monthly during the life of the Surviving Spouse.

3.3 Adjustments

The annual Supplemental Retirement Benefit or the annual Spouse's Supplemental Retirement Benefit will not be decreased or increased on account of any increase or decrease in the Basic Pension Plan Benefit, Cash Balance Restoration Plan Benefit, or Social Security Benefit occurring after a Participant's Retirement Date or death.

3.4 Payment

(a)

Subject to subsections (b), (c) and (d), a Participant’s Pre-Section 409A Supplemental Retirement Benefit will be paid as soon after the Participant's Retirement Date as is reasonably practicable, and a Participant’s Post-Section 409A Supplemental Retirement Benefit will be paid or commence upon such Participant’s Separation from Service (or such other commencement date as is determined under Section 3.1). If an annuity payment is elected pursuant to Section 3.1, for purposes of the payment of such Participant’s Pre-Section 409A Supplemental Retirement Benefit, such Pre-Section 409A Supplemental Retirement Benefit will be paid monthly, beginning on the last day of the month of the Participant's Retirement Date and will continue to be paid monthly during the life of the Participant, the last payment to be made to the Participant’s spouse or, if none, to the Participant’s estate, on the last day of the month in which the death of the Participant occurs. If an annuity payment is elected pursuant to Section 3.1, for purposes of the payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit, such Post-Section 409A Supplemental Retirement Benefit will be paid monthly, beginning on the last day of the month of the Participant's Separation from Service (or such other commencement date as is determined under Section 3.1) and will continue to be paid monthly during the life of the Participant, the last payment to be made to the Participant’s spouse or, if none, to the Participant’s estate, on the last day of the month in which the death of the Participant occurs. If the Participant’s designated beneficiary is the Participant’s Surviving Spouse, the Surviving Spouse will receive the Spouse's Supplemental Retirement Benefit, which will be paid monthly, and will commence on the last day of the month following the month in which the Participant dies and will continue during the life of the Surviving Spouse. If the Participant’s designated beneficiary is not the Participant’s Surviving Spouse, and the designated beneficiary survives the Participant, the designated beneficiary will receive the survivor benefit under the annuity elected by the Participant, which will be paid monthly, and will commence on the last day of the month following the month in which the Participant does and will continue during the life of the designated beneficiary. In all cases, the monthly benefit shall equal the annual benefit divided by 12.

(b)

A Participant’s Pre-Section 409A Supplemental Retirement Benefit shall be paid in accordance with Section 3.1(c)(i) and a Participant’s Post-Section 409A Supplemental Retirement Benefit shall be paid in accordance with Section 3.1(c)(ii).

(c)

Notwithstanding the foregoing, in the case of a Participant who is a Specified Employee on the date of such Participant’s Separation from Service, the payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit to such Participant shall not be made before the date which is six months after the date of such Participant’s Separation from Service (or, if earlier, the date such Participant’s death) in accordance with Section 409A(a)(2)(B)(i) of the Code and the Treasury Regulations thereunder. Any payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit to which such Participant otherwise would have been entitled during the first six months following the date of such Participant’s Separation from Service shall be accumulated (with interest at the annual rate of interest on 30-year Treasury securities for the November next preceding the first day of the calendar year in which such Participant’s Separation from Service occurs) and paid on the first day of the seventh month following the date of such Participant’s Separation from Service (or, if earlier, the date of such Participant’s death) in accordance with Section 409A(a)(2)(B)(i) and the Treasury Regulations thereunder.

(d)

The time or schedule of payment of any payment of a Participant’s Post-Section 409A Supplemental Retirement Benefit under the Plan shall not be subject to acceleration, except as provided under Treasury Regulations promulgated in accordance with Section 409A(a)(3) of the Code.

3.5	Conformance of Time and Form of Payment under the Cash Balance Restoration Plan

Prior to a Participant’s Transfer Date:

(a)

The payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit to such Participant under this Plan shall be made or commence on the date of the payment or commencement of such Participant’s “Post-Section 409A Benefit” (as defined in the Cash Balance Restoration Plan) under the Cash Balance Restoration Plan, and the form of payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit under this Plan shall be the same as the form of payment of such Participant’s “Post-Section 409A Benefit” under the Cash Balance Restoration Plan.

(b)

In the event that a Participant elects to change the form of the payment of such Participant’s “Post-Section 409A Benefit” (as defined in the Cash Balance Restoration Plan) under the Cash Balance Restoration Plan, such Participant shall be deemed to have elected to change the form of the payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit under this Plan to the form of the payment of such Participant’s “Post-Section 409A Benefit” under the Cash Balance Restoration Plan. Any such election shall be subject to Section 3.1(c)(ii)(C) and the provisions of the Cash Balance Restoration Plan and, in any event, the time and form of payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit under this Plan shall be the same as the time and form of payment of such Participant’s “Post-Section 409A Benefit” under the Cash Balance Restoration Plan.

3.6	Conformance of Time and Form of Payment of Cash Balance Restoration Benefit

On and after a Participant’s Transfer Date:

(a)

The payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit to such Participant under this Plan shall be made or commence on the date of the payment or commencement of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan, and the form of payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit under this Plan shall be the same as the form of payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan.

(b)

In the event that a Participant elects to change the form of the payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan, such Participant shall be deemed to have elected to change the form of the payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit under this Plan to the form of the payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan. Any such election shall be subject to Section 4.3(b) or (d) and, in any event, the time and form of payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit under this Plan shall be the same as the time and form of payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan.

SECTION 4

CASH BALANCE RESTORATION BENEFITS

4.1 Cash Balance Restoration Benefit

(a)

The Cash Balance Restoration Benefit payable to a Participant shall be determined under Section 4.2. The Participant’s Cash Balance Restoration Benefit serves two purposes. First, the Cash Balance Restoration Benefit provides benefits for the Participant in excess of the limitations on benefits under the Basic Pension Plan imposed by Section 415 of the Code. The portion of the Plan providing these benefits is intended to be an "excess benefit plan" as defined in Section 3(36) of ERISA (as defined below). Second, the Cash Balance Restoration Benefit provides benefits for the Participant in excess of the limitations on benefits under the Basic Pension Plan imposed by Section 401(a) (17) of the Code.

(b)

Effective as of the Participant’s Transfer Date, a Participant’s Cash Balance Restoration Plan Benefit (determined immediately prior to the Participant’s Transfer Date) shall be transferred from the Cash Balance Restoration Plan to this Plan, and the Cash Balance Restoration Plan shall cease to provide such Cash Balance Restoration Plan Benefit to such Participant and this Plan shall thereafter provide the Cash Balance Restoration Benefit to such Participant in lieu thereof. The transfer of such Participant’s Cash Balance Restoration Plan Benefit to this Plan shall be made in accordance with Section 409A of the Code and the Treasury Regulations thereunder and the time and form of payment of the Cash Balance Restoration Benefit under this Plan (determined as of such Participant’s Transfer Date) shall be the same as the time and form of payment of the Cash Balance Restoration Plan Benefit under the Cash Balance Restoration Plan (determined immediately prior to such Participant’s Transfer Date).

(c)

Effective as of the Participant’s Transfer Date, the Participant shall cease to be a participant in the Cash Balance Restoration Plan and no further benefits shall be paid to or in respect of such Participant under the Cash Balance Restoration Plan. In no event shall the Participant be paid a Cash Balance Restoration Benefit under this Plan that duplicates any benefit paid under the Cash Balance Restoration Plan.

4.2 Amount of Cash Balance Restoration Benefits

The Cash Balance Restoration Benefit payable to a Participant shall be determined under subsections (a) and (b), based on such benefits payable in the form of a straight life annuity without a cost of living adjustment feature unless one is provided under the Basic Pension Plan.

(a)

415 Make-Up

The benefits payable under this subsection (a) to a Participant whose benefits under the Basic Pension Plan are limited by the provisions of Section 415 of the Code incorporated in the Basic Pension Plan, or to his beneficiary(ies), shall equal the excess, if any, of:

(i)	the benefits which would be paid to such Participant or on his behalf to his beneficiary(ies) under the Basic Pension Plan, if the provisions of such Plan were administered without regard to the benefit limitations under Section 415 of the Code set forth in the Basic Pension Plan, over

(ii)	the benefits which are paid to such Participant or on his behalf to his beneficiary(ies) under the Basic Pension Plan.

(b) 401(a) (17) Make-Up

The benefits payable under this subsection (b) to a Participant whose benefits under the Basic Pension Plan are limited by the covered compensation limitations of Section 401(a)(17) of the Code incorporated in the Basic Pension Plan, or to his beneficiary(ies), shall equal the excess, if any, of:

(i)

the benefits which would be paid to such Participant or on his behalf to his beneficiary(ies) under the Basic Pension Plan, and, if applicable, to the Participant, under subsection (a), if the provisions of such Plan were administered without regard to the covered compensation limitations under Section 401(a)(17) of the Code set forth in the Basic Pension Plan (and, with respect to covered compensation paid or payable in plan years beginning on or after January 1, 2007, with a maximum compensation limit for each plan year of Two Million Dollars ($2,000,000)), over

(ii)	the benefits which are paid to such Participant or on his behalf to his beneficiary(ies) under the Basic Pension Plan and, if applicable to the Participant, under subsection (a).

(c)	Conformance with Treasury Regulations

The benefits payable under subsections (a) and (b) are determined under the formula determining benefits under the Basic Pension Plan, and the benefits payable under subsections (a) and (b) are determined as an amount offset by the benefits provided under the Basic Pension Plan. The benefits payable under Section 4.2 shall be determined in a manner consistent with Treasury Regulation Sections 1.409A-2(a)(9) and 1.409A-3(j)(5) (relating to nonqualified deferred compensation plans linked to qualified employer plans). Any amendment of the Basic Pension Plan shall be taken into account under this Plan only to the extent permitted under Treasury Regulation Sections 1.409A-2(a)(9) and 1.409A-3(j)(5). Any reference to the interest and mortality factors (or actuarial methods and assumptions) specified in the Basic Pension Plan shall mean the applicable interest and mortality factors (or actuarial methods or assumptions) specified under the terms of the Basic Pension Plan, determined based on the terms in effect on December 31, 2008.

4.3 Payment of Benefits

(a)

Distribution Options for Certain Participants

(i)

In the case of a Participant who is an eligible employee in the Cash Balance Restoration Plan and is a Participant under this Plan as of December 31, 2005, the payment of such Participant’s Cash Balance Restoration Benefit under this Plan shall be made in accordance with this subsection (a).

(ii)

Unless the Participant exercises the Lump Sump Option and receives a lump sum distribution from the Basic Pension Plan, the payment of such Participant’s Pre-Section 409A Cash Balance Restoration Benefit under this Plan shall be in the same payment form and at the same time as the payment of benefits to the Participant or on his behalf to his beneficiary(ies) under the Basic Pension Plan. In the event a Participant receives a lump sum distribution from the Basic Pension Plan, payment of such Participant’s Pre-Section 409A Cash Balance Restoration Benefit under this Plan will be made in the form of a straight life annuity. However, the Participant may request, in writing, payment of such Participant’s Pre-Section 409A Cash Balance Restoration Benefit under one of the following alternatives provided such request is filed with Sempra Energy at least three months prior to his Cash Balance Restoration Benefit Retirement Date or Cash Balance Restoration Benefit Termination under the Basic Pension Plan:

(A)

The Participant may request payment of such Participant’s Pre-Section 409A Cash Balance Restoration Benefit under any of the other annuity options for which he is eligible under the Basic Pension Plan. The amount of such optional annuity benefit with respect to his or her Pre-Section 409A Cash Balance Restoration Benefit under this Plan shall be computed as specified in Section 4.2 of this Plan using the interest and mortality factors specified in the Basic Pension Plan. The request will be subject to approval of the Company's Senior Human Resources Officer and, if approved, will be irrevocable as long as the Participant receives a lump sum distribution from the Basic Pension Plan.

(B)

The Participant may request payment of such Participant’s Pre-Section 409A Cash Balance Restoration Benefit in a lump sum. The amount of the distribution with respect to his or her Pre-Section 409A Cash Balance Restoration Benefit under this Plan shall be computed as specified in Section 4.2 of this Plan using the actuarial factors specified in the Basic Pension Plan. In the event such a request is timely filed, the request shall be considered by the Senior Human Resources Officer who shall have the sole discretion, considering the best interests of the Company, to allow a lump sum distribution. The decision of the Senior Human Resources Officer shall be final. The Participant will be required to show good reason for receiving a lump sum distribution and, file the request at least three months prior to separation from service as a condition of having the request approved. If the lump sum pay out is approved, the lump sum form of pay out shall be irrevocable even if the Participant changes his election under the Basic Pension Plan.

The Participant’s beneficiary(ies) with respect to his or her Pre-Section 409A Cash Balance Restoration Benefit under this Plan shall be exactly the same as his beneficiary(ies) under the Basic Pension Plan unless he elects and receives a lump sum distribution from the Basic Pension Plan. In this event, the following provisions will apply if such Participant’s Pre-Section 409A Cash Balance Restoration Benefit under this Plan is paid in the form of a joint and survivor annuity.

The joint and survivor annuity is only available with respect to such Participant’s Pre-Section 409A Cash Balance Restoration Benefit if the Participant designates his or her spouse as beneficiary or obtains spousal consent to the designation of another beneficiary in the same manner as under the Basic Pension Plan. If the spouse, or beneficiary dies before the Participant’s Cash Balance Restoration Benefit Retirement Date under the Basic Pension Plan, the joint and survivor annuity with respect to such Participant’s Pre-Section 409A Cash Balance Restoration Benefit is canceled and the benefit is paid in the form of a straight life annuity.

(iii)

The payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan shall be made in the lump sum or annuity form of payment that applied to such Participant’s “Post-Section 409A Benefit” under the Cash Balance Restoration Plan (determined immediately prior to such Participant’s Transfer Date), and shall be made or commence upon the Participant’s Separation from Service, or such later payment or commencement date as applied to such Participant’s “Post-Section 409A Benefit” under the Cash Balance Restoration Plan (determined immediately prior to such Participant’s Transfer Date). The amount of the Participant’s lump sum distribution with respect to his Post-Section 409A Cash Balance Restoration Benefit under this Plan shall be computed as specified in Section 4.2 of this Plan using the actuarial factors specified in the Basic Pension Plan.

(A)

In the event the Participant’s Cash Balance Restoration Benefit shall be made in an annuity form of payment, the payment of the Participant’s Post-Section 409A Cash Balance Restoration Benefit will be made under one of the following annuity options, whichever is applicable: (I) a straight life annuity, (II) a joint and 50% survivor annuity, and (III) a joint and 100% survivor annuity. The amount of such optional annuity benefit with respect to such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan shall be computed as specified in Section 4.2 of this Plan using the interest and mortality factors specified in the Basic Pension Plan.

(B)

Except as provided in subsection (b), such Participant may not change the form and time of payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan on or after such Participant’s Transfer Date.

(iv)

A lump sum payment of a Participant’s Post-Section 409A Cash Balance Restoration Benefit under this subsection (a) shall be paid on such date as is determined by Sempra Energy within thirty (30) days following the Participant’s Separation from Service, or such later payment date as applied to such Participant’s “Post-Section 409A Benefit” under the Cash Balance Restoration Plan (determined immediately prior to such Participant’s Transfer Date). If an annuity payment applies for purposes of the payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this subsection (a), such Post-Section 409A Cash Balance Restoration Benefit shall be paid monthly, beginning on the last day of the month of the Participant’s Separation from Service, or such later commencement date as applied to such Participant’s “Post-Section 409A Benefit” under the Cash Balance Restoration Plan (determined immediately prior to such Participant’s Transfer Date) and shall continue to be paid monthly during the life of the Participant and the life of the Participant’s designated beneficiary, if any (if such beneficiary survives the Participant). In all cases, the monthly benefit shall equal the annual benefit divided by 12.

(b)

Changes in Distribution Option for Certain Participants

A Participant described in subsection (a) may elect to change the form of the payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan on or after the Participant’s Transfer Date, as follows:

(i)

The Participant may elect, in writing, to change the form of payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit to any of the following options: (A) a lump sum, (B) a straight life annuity, (C) a joint and 50% survivor annuity, and (D) a joint and 100% survivor annuity. The amount of such optional benefit under this Plan shall be computed as specified in Section 4.2 of this Plan using the interest and mortality factors specified in the Basic Pension Plan. The Participant’s election shall be subject to paragraphs (ii), (iii), (iv), (v), (vi) and (vii). Except as provided in paragraph (vi), the Participant’s election under this paragraph (i) shall be irrevocable. The joint and survivor annuity is only available under subparagraph (C) or (D) if the Participant designates his or her spouse as beneficiary or obtains spousal consent to the designation of another beneficiary in the same manner as under the Basic Pension Plan as part of the Participant’s election. If the spouse, or beneficiary dies before the Participant’s Separation from Service, the joint and survivor annuity elected under this paragraph (i) is canceled and the benefit is paid in the form of a straight life annuity; provided, that the straight life annuity is actuarially equivalent, applying reasonable actuarial methods and assumptions, to the joint and survivor annuity in effect prior to such cancellation, as determined under Treasury Regulation Section 1.409A-2(a)(2)(ii).

(ii)

The Participant’s election under paragraph (i) must be made prior to the Participant’s Separation from Service.

(iii)

If the Participant’s form of payment, as in effect at the time of election under paragraph (i), is an annuity, such Participant’s election under paragraph (i)(B), (C) or (D) (an election of an alternative annuity form of payment) shall be effective immediately and paragraph (v) shall not apply to such Participant’s election; provided, that the alternative annuity form of payment elected by the Participant is actuarially equivalent applying reasonable actuarial methods and assumptions to the annuity form of payment, as in effect at the time of the election, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(iv)

Except as provided in paragraph (iii), the Participant’s election under paragraph (i) shall not take effect until 12 months after his election is made, in accordance with Treasury Regulation Section 1.409A-2(b)(1)(i). If the Participant has a Separation from Service before the election under paragraph (i) becomes effective, the election under paragraph (i) shall terminate and the Participant’s Post-Section 409A Cash Balance Restoration Benefit shall be paid in the form of payment as in effect at the time of the election under paragraph (i).

(v)

Except as provided in paragraph (iii), in the event the Participant’s election under paragraph (i) becomes effective, the payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under the option shall be deferred for a period of five years from the date such payment would otherwise have been paid (or, in the case of a life annuity treated as a single payment, five years from the date the first amount was scheduled to be paid), in accordance with Treasury Regulation Section 1.409A-2(b)(1)(ii).

(vi)

The Participant may elect to change the annuity option elected under paragraph (i) to another annuity option specified under paragraph (i) and such election shall become effective immediately, provided, that such change is made prior to the commencement of the payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan; and, provided, further, that the annuity form of payment is actuarially equivalent, applying reasonable actuarial methods and assumptions, to the annuity form of payment, as in effect at the time of the election, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(vii)

Any change in a Participant’s form of payment under this subsection (b) shall be made in accordance with Treasury Regulation Section 1.409A-2(b).

(c)

Distribution Options for other Participants

Except as provided in subsection (a) or paragraph (iv), the payment of a Participant’s Cash Balance Restoration Benefit under this Plan shall be made in the lump sum or annuity form of payment that applied to such Participant’s Cash Balance Restoration Plan Benefit (determined immediately prior to such Participant’s Transfer Date), and shall be made or commence upon the Participant’s Separation from Service, or such later payment or commencement date as applied to such Participant’s Cash Balance Restoration Plan Benefit (determined immediately prior to such Participant’s Transfer Date). The amount of the Participant’s lump sum distribution with respect to his Cash Balance Restoration Benefit under this Plan shall be computed as specified in Section 4.2 of this Plan using the actuarial factors specified in the Basic Pension Plan.

(i)

In the event the Participant’s Cash Balance Restoration Benefit shall be made in an annuity form of payment, the payment of Participant’s Cash Balance Restoration Benefit will be made under any of the following annuity options: (A) a straight life annuity, (B) a joint and 50% survivor annuity, and (C) a joint and 100% survivor annuity. The amount of such optional annuity benefit under this Plan shall be computed as specified in Section 4.2 of this Plan using the interest and mortality factors specified in the Basic Pension Plan.

(ii)	Except as provided in subsection (d), such Participant may not change the form and time of payment of such Participant’s Cash Balance Restoration Benefit under this Plan on or after such Participant’s Transfer Date.

(iii)

A lump sum payment under this subsection (c) shall be paid on such date as is determined by Sempra Energy within thirty (30) days following the Participant’s Separation from Service, or such later payment date as applied to such Participant’s Cash Balance Restoration Plan Benefit (determined immediately prior to such Participant’s Transfer Date). An annuity under this subsection (c) shall be paid monthly, beginning on the last day of the month of the Participant’s Separation from Service, or such later payment date as applied to such Participant’s Cash Balance Restoration Plan Benefit (determined immediately prior to such Participant’s Transfer Date) and shall continue to be paid monthly during the life of the Participant and the life of the Participant’s designated beneficiary, if any (if such beneficiary survives the Participant). In all cases, the monthly benefit shall equal the annual benefit divided by 12.

(iv)

In the event that such Participant was not a participant in the Cash Balance Restoration Plan immediately prior to such Participant’s Transfer Date, such Participant’s Cash Balance Restoration Benefit under this Plan shall be made in a lump sum form of payment upon the Participant’s Separation from Service.

(d)

Changes in Distribution Option for other Participants

A Participant described in subsection (c) may elect to change the form of the payment of such Participant’s Cash Balance Restoration Benefit under this Plan on or after the Participant’s Transfer Date, as follows:

(i)

The Participant may elect, in writing, to change the form of payment of such Participant’s Cash Balance Restoration Benefit to any of the following options: (A) a lump sum, (B) a straight life annuity, (C) a joint and 50% survivor annuity, and (D) a joint and 100% survivor annuity. The amount of such optional benefit under this Plan shall be computed as specified in Section 4.2 of this Plan using the interest and mortality factors specified in the Basic Pension Plan. The Participant’s election shall be subject to paragraphs (ii), (iii), (iv), (v), (vi) and (vii). Except as provided in paragraph (vi), the Participant’s election under this paragraph (i) shall be irrevocable. The joint and survivor annuity is only available under subparagraph (C) or (D) if the Participant designates his or her spouse as beneficiary or obtains spousal consent to the designation of another beneficiary in the same manner as under the Basic Pension Plan as part of the Participant’s election. If the spouse, or beneficiary dies before the Participant’s Separation from Service, the joint and survivor annuity is canceled and the benefit is paid in the form of a straight life annuity; provided, that the straight life annuity is actuarially equivalent, applying reasonable actuarial methods and assumptions, to the joint and survivor annuity in effect prior to such cancellation, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(ii)

The Participant’s election under paragraph (i) must be made prior to the Participant’s Separation from Service.

(iii)

If the Participant’s form of payment, as in effect at the time of the election under paragraph (i), is an annuity, such Participant’s election under paragraph (i)(B), (C) or (D) (an election of an alternative annuity form of payment) shall be effective immediately and paragraph (v) shall not apply to such Participant’s election; provided, that the alternative annuity form of payment elected by the Participant is actuarially equivalent applying reasonable actuarial methods and assumptions to the annuity form of payment, as in effect at the time of the election, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(iv)

Except as provided in paragraph (iii), the Participant’s election under paragraph (i) shall not take effect until 12 months after the date his or her election is made in accordance with Treasury Regulation Section 1.409A-2(b)(1)(i). If the Participant has a Separation from Service before the election under paragraph (i) becomes effective, the election under paragraph (i) shall terminate and the Participant’s benefit shall be paid in the form of payment as in effect at the time of the election under paragraph (i).

(v)

Except as provided in paragraph (iii), in the event the Participant’s election under paragraph (i) becomes effective, the payment of such Participant’s benefit under the option be deferred for a period of five years from the date such payment would otherwise have been paid (or, in the case of a life annuity treated as a single payment, five years from the date the first amount was scheduled to be paid), in accordance with Treasury Regulation Section 1.409A-2(b)(1)(ii).

(vi)

The Participant may elect to change an annuity form of payment elected under paragraph (i) to another annuity form of payment specified under paragraph (i)(B), (C) or (D), and such election shall be effective immediately; provided, that such change is made prior to the commencement date of the payment of benefits under this Plan; and, provided, further, that the annuity form of payment is actuarially equivalent applying reasonable actuarial methods and assumptions to the annuity form of payment, as in effect at the time of the election, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(vii)

Any change in a Participant’s form of payment under this subsection (d) shall be made in accordance with Treasury Regulation Section 1.409A-2(b).

(e)

Death Benefits

If a Participant dies on or after the Participant’s Transfer Date and prior to the commencement of the payment of such Participant’s Cash Balance Restoration Benefit under this Plan on or after his or her Separation from Service (or, in the case of a Participant described in subsection (a), the Participant dies on or after the Participant’s Transfer Date and prior to the commencement of the payment of such Participant’s Pre-Section 409A Cash Balance Restoration Death Benefit (if any), under this Plan on or after such Participant’s Cash Balance Restoration Benefit Retirement Date or Cash Balance Restoration Benefit Termination), the payment of death benefits to such Participant’s beneficiary(ies) shall be made in accordance with this subsection (e).

(i)

The death benefits payable to such Participant’s beneficiary(ies) under this subsection (e) shall be computed as specified in Section 4.2 of this Plan using the actuarial factors specified in the Basic Pension Plan.

(ii)

The death benefits payable to such Participant’s beneficiary(ies) under this subsection (e) shall be in lieu of any benefits that would have been payable under the other provisions of this Section 4.3, if such Participant had survived until the date of commencement of benefits.

(iii)

The death benefits payable to such Participant’s beneficiary(ies) under this subsection (e) shall be payable in a lump sum payment on such date as is determined by Sempra Energy during the thirty (30) day period commencing upon such Participant’s death; provided, however, that, in the case of a Participant described in subsection (a), such Participant’s Pre-Section 409A Cash Balance Restoration Death Benefit (if any) shall be paid in the same payment form and at the same time as the payment of pre-commencement death benefits on behalf of such Participant under the Basic Pension Plan and such Participant’s Post-Section 409A Cash Balance Restoration Death Benefit shall be payable in a lump sum on such date as is determined by Sempra Energy during the thirty (30) day period commencing upon such Participant’s death.

(iv)

For purposes of this subsection (e),

(A)

in the case of a Participant described in subsection (a), such Participant’s “Pre-Section 409A Cash Balance Restoration Death Benefit” means the portion of the death benefits payable to such Participant’s beneficiary(ies) under this subsection (e), if any, to which such Participant had a legal binding right, and which was earned and vested, as of December 31, 2004, determined in accordance with Section 409A of the Code and Treasury Regulation Section 1.409A-6. Such Participant’s “Pre-Section 409A Cash Balance Restoration Death Benefit” shall be determined by the terms of the Cash Balance Restoration Plan and the Basic Pension Plan, as in effect as of October 3, 2004 and in a manner consistent with paragraph (E)(i) and Treasury Regulation Section 1.409A-6(a)(3)(i), and

(B)

in the case of a Participant described in subsection (a), such Participant’s “Post-Section 409A Cash Balance Restoration Death Benefit” means the death benefit payable to such Participant’s beneficiary(ies) under this subsection (e), less such Participant’s Pre-Section 409A Cash Balance Restoration Death Benefit.

(f)

Mandatory Distribution

Notwithstanding Section 3 and subsections (a), (b), (c), (d) and (e), if the actuarial value of a Participant’s benefit under this Plan as of the date of the Participant’s Separation from Service is less than $10,000, the benefit shall be distributed in a lump sum upon the Participant’s Separation from Service in accordance with Treasury Regulation Section 1.409A-3(j)(4)(v). Such lump sum payment shall be paid on such date as is determined by Sempra Energy within thirty (30) days following the Participant’s Separation from Service. Such lump sum payment shall be made only if such payment satisfies the requirement of Treasury Regulation Section 1.409A-3(j)(4)(v)(A).

(g)

Distributions to Specified Employees

Notwithstanding the foregoing, in the case of a Participant who is a Specified Employee on the date of such Participant’s Separation from Service, the payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit to such Participant shall not be made before the date which is six months after the date of such Participant’s Separation from Service (or, if earlier, the date such Participant’s death) in accordance with Section 409A(a)(2)(B)(i) of the Code and the Treasury Regulations thereunder. Any payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit to which such Participant otherwise would have been entitled during the first six months following the date of such Participant’s Separation from Service shall be accumulated (with interest at the annual rate of interest on 30-year Treasury securities for the November next preceding the first day of the calendar year in which such Participant’s Separation from Service occurs) and paid on the first day of the seventh month following the date of such Participant’s Separation from Service (or, if earlier, the date of such Participant’s death) in accordance with Section 409A(a)(2)(B)(i) and the Treasury Regulations thereunder.

(h)

Prohibition on Acceleration of Distributions

The time or schedule of payment of any payment of a Participant’s Post-Section 409A Cash Balance Restoration Benefit under the Plan shall not be subject to acceleration, except as provided under Treasury Regulations promulgated in accordance with Section 409A(a)(3) of the Code.

(i)

Conformance of Time and Form of Payment under Section 3

(i)

The payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit to such Participant under Section 3 shall be made or commence on the date of the payment or commencement of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan, and the form of payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit shall be the same as the form of payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Section 4.

(ii)

In the event that a Participant elects to change the form of the payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan, such Participant shall be deemed to have elected to change the form of the payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit to the form of the payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Plan. Any such election shall be subject to the provisions of subsection (b) or (d), as applicable, and the provisions of Section 3 and, in any event, the time and form of payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit shall be the same as the time and form of payment of such Participant’s Post-Section 409A Cash Balance Restoration Benefit under this Section 4.

SECTION 5

SUPPLEMENTAL PRERETIREMENT SPOUSE'S DEATH BENEFITS

5.1 Benefit

The Spouse's Death Benefit that will be paid to a Surviving Spouse of a Participant who dies prior to having a Separation from Service prior to his Retirement Date is a lump sum payment based on the Actuarial Value of an annuity equal to (a) minus (b) when:

(a)

is 100% of the Participant’s accrued benefit calculated in accordance with 3.1(a). If the Participant is under age 55 at the time of death, the age 55 early retirement factor shall be used, and

(b)

is the Surviving Spouse's Preretirement Spouse's Benefit.

5.2 Form of Benefit

The Spouse’s Death Benefit shall be paid in the form of a lump sum payment on such date as is determined by Sempra Energy within thirty (30) days following the Participant’s death.

SECTION 6

SUPPLEMENTAL DISABILITY BENEFITS

6.1 Amount

The annual Supplemental Disability Benefit payable to a Participant is equal to (a) minus (b) when (a) is 60% multiplied by the total of the Participant's Average Bonus and annual rate of Earnings in effect on the day immediately preceding the day the Participant becomes eligible, and (b) is the sum of

(i)

the Participant's Basic Disability Plan Benefit, and any other Company provided disability plan, plus

(ii)

the Participant’s Voluntary Disability Benefit, plus

(iii)

the amount of benefits for which the Participant is eligible under the provisions of any federal or state law providing payments on account of disability, as these payments are defined in the Basic Disability Plan, during the period of eligibility for a Supplemental Disability Benefit. If (a) minus (b) results in zero or less, then no Supplemental Disability Benefit is payable. If the Basic Disability Plan Benefit increases under the Basic Disability Plan, or the Voluntary Disability Benefit increases, the Supplemental Disability Benefit will be decreased by the same amount.

The Supplemental Disability Benefit is intended to constitute a disability pay benefit that is exempt from Section 409A of the Code pursuant to Treasury Regulation Section 1.409A-1(a)(5).

6.2

Payment

Eligibility for a Supplemental Disability Benefit is determined by the Committee. The Supplemental Disability Benefit will be paid monthly. The last Supplemental Disability Benefit will be paid to the Participant at the earliest of (i) when the Committee deems that the Participant is no longer disabled, (ii) when Participant starts receiving a Supplemental Retirement Benefit, or (iii) when the Participant attains age 65.

SECTION 7

ADMINISTRATION

7.1 Authority of Committee

This Plan shall be administered by the Committee. Subject to the express provisions of this Plan, the Committee shall have full and final authority to interpret this Plan, to prescribe, amend and rescind rules, regulations and guides relating to the Plan, and to make any other determinations that it believes necessary or advisable for the administration of the Plan. The Committee may delegate certain responsibilities in the administration of the Plan. All decisions and determinations by the Committee shall be final and binding upon all parties.

7.2 Calculation of Benefits

Any and all payments to be made under this Plan and all Actuarial Equivalents shall be calculated by the Company's regularly employed independent actuaries, and their determinations shall be final and binding on all parties.

SECTION 8

MISCELLANEOUS

8.1 Amendment, Termination or Removal of Participant

(a)

The Committee may, in its sole discretion, terminate, suspend, or amend this Plan at any time, in whole or in part. However, no termination, amendment or suspension of the Plan will affect a retired or disabled Participant's right or the right of a Surviving Spouse to continue receiving a benefit in accordance with this Plan as in effect on the date such Participant or Surviving Spouse began to receive a benefit under this Plan. Furthermore, if a Participant then qualifies for Retirement under Section 1.29, such termination, amendment or suspension of the Plan will not affect such Participant’s right or the right of such Participant’s Surviving Spouse to receive the Supplemental Retirement Benefit or the Spouse’s Supplemental Retirement Benefit to which he or she would have been entitled if such Participant’s Retirement Date had occurred immediately prior to such termination, amendment or suspension, as determined in accordance with this Plan as in effect immediately prior to such termination, amendment or suspension. Furthermore, if the Committee shall amend or terminate this Plan, the Company shall be liable for any benefits accrued under Section 4 of this Plan as of the date of such amendment or termination determined on the basis of each Participant’s presumed termination of employment as of such date.

(b)

The Committee may, in its sole discretion, remove an executive as a Participant in this Plan due to changed job responsibilities or other changed circumstances as long as no benefits are then being paid to the Participant under this Plan. However, if a Participant then qualifies for Retirement under Section 1.29, such removal will not affect such Participant’s right or the right of such Participant’s Surviving Spouse to receive the Supplemental Retirement Benefit or the Spouse’s Supplemental Retirement to which he or she would have been entitled if such Participant’s Retirement Date had occurred immediately prior to such removal, as determined in accordance with this Plan as in effect immediately prior to such removal.

8.2	No Employment Right

Nothing contained herein will confer upon any Participant the right to be retained in Employment, nor will it interfere with the right of his Employer to discharge or otherwise deal with the Participant without regard to the existence of this Plan.

8.3 Funding

This Plan is unfunded, and the Employer will make Plan Benefit Payments solely on a current disbursement basis. Participants and their Beneficiaries shall have no legal or equitable rights, claims, or interest in any specific property or assets of the Employer, and the rights of the Participants and Beneficiaries shall be no greater than those of unsecured general creditors.

8.4 Allocation of Costs

Amounts accrued as expenses under this Plan, and the cost of any life insurance policies purchased to fund for benefits payable under this Plan, shall be allocated to Employers whose employees are Participants in this Plan.

SECTION 9

BENEFITS DEFERRED UNDER DEFERRED COMPENSATION PLAN

Notwithstanding any other provision of the Plan, if a Participant has elected to defer the Participant’s “SERP Lump Sum” as defined in the Deferred Compensation Plan, pursuant to the terms of the Sempra Energy Deferred Compensation Plan, no retirement benefits shall be payable under this Plan to the Participant, to the Participant’s Surviving Spouse or to any other person effective immediately at and after the SERP Lump Sum has been credited to the Participant’s account under the Sempra Energy Deferred Compensation Plan.

SECTION 10

SECTION 409A OF THE CODE

10.1

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 Notices 2006-79 and 2007-86 and other applicable authority issued by the Internal Revenue Service). As provided in Internal Revenue Service Notices 2006-79 and 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, 2006 and on or before December 31, 2006, the election or amendment shall apply only to amounts that would not otherwise be payable in 2006 and shall not cause an amount to be paid in 2006 that would not otherwise be payable in 2006; and, with respect to an election or amendment to change a time and form of payment under this Plan made on or after January 1, 2007 and on or before December 31, 2007, the election or amendment may apply only to amounts that would not otherwise be payable in 2007 and may not cause an amount to be paid in 2007 that would not otherwise be payable in 2007; and, with respect to an election or amendment to change a time and form of payment under this Plan made on or after January 1, 2008 and on or before December 31, 2008, the election or amendment may apply only to amounts that would not otherwise be payable in 2008 and may not cause an amount to be paid in 2008 that would not otherwise be payable in 2008. If Sempra Energy determines that any deferred compensation amounts under this Plan subject to Section 409A of the Code do not comply with Sections 409A(a)(2), (3) and (4) of the Code, the Treasury Regulations thereunder and other applicable authority issued by the Internal Revenue Service, Sempra Energy may amend this Plan, or take such other actions as Sempra Energy deems reasonably necessary or appropriate, to ensure that such amounts comply with the requirements of Section 409A of the Code, the Treasury Regulations thereunder and other applicable authority issued by the Internal Revenue Service. In the case of any deferred compensation amounts under this Plan that are subject to Section 409A of the Code, if any provision of the Plan would cause such amounts to fail to so comply, such provision shall be deemed amended, or shall not be effective and shall be null and void, to the extent necessary to cause such amounts to comply with Section 409A(a)(2), (3) and (4) of the Code, the Treasury Regulations thereunder and other applicable authority issued by the Internal Revenue Service.

10.2

The Plan provides that benefits under the Plan are determined after an offset of the benefits provided under the Basic Pension Plan (which is a qualified employer plan, as defined in Treasury Regulation Section 1.409A-1(a)(2)). Accordingly, the Plan is intended to be a nonqualified deferred compensation plan subject to Treasury Regulation Sections 1.409A-2(a)(9) and 1.409A-3(j)(5). Any amendment of the Basic Pension Plan shall be taken into account under this Plan only to the extent permitted under Treasury Regulation Sections 1.409A-2(a)(9) and 1.409A-3(j)(5). Any reference to the interest and mortality factors (or actuarial methods and assumptions) specified in the Basic Pension Plan shall mean the applicable interest and mortality factors (or actuarial methods or assumptions) specified under the terms of the Basic Pension Plan, determined based on the terms in effect on December 31, 2008.

SECTION 11

CLAIMS PROCEDURE

11.1 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 Compensation Committee, setting forth his claim. The request must be addressed to the Compensation 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 Compensation Committee.

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

11.2 Claim Decision

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

If the claim is denied in whole or in part, the Compensation 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 Compensation Committee within 60 days after receipt of the Compensation Committee’s notice of denial of claim. The Claimant’s failure to appeal the denial of the claim by the Compensation Committee in writing within the 60 day period shall render the Compensation Committee’s determination final, binding, and conclusive.

11.3 Request for Review

With 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 Compensation Committee of Sempra Energy, at its 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 Compensation 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 Compensation Committee’s initial determination with respect to the claim.

The Compensation Committee shall advise the Claimant in writing of the Compensation Committee’s determination of the review within 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 60 day period infeasible, but in no event shall the Compensation Committee render a determination regarding the denial of a claim later than 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 Compensation Committee expects to render a review decision.

11.4 Review of Decision

The Compensation 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.

SECTION 12

MISCELLANEOUS

12.1 Unsecured General Creditor

Participants and their beneficiaries, heirs, successors, and assigns shall have no legal or equitable rights, claims, or interest in any specific property or assets of the Company. No assets of the Company shall be held in any way as collateral security for the fulfilling of the obligations of the Company under this Plan. Any and all of the Company’s assets shall be, and remain, the general unpledged, unrestricted assets of the Company. The Company’s obligation under the Plan shall be merely that of an unfunded and unsecured promise of the Company to pay money in the future, and the rights of the Participants and Beneficiaries shall be no greater than those of unsecured general creditors. It is the intention of the Company that this Plan be unfunded for purposes of the Code and Title I of ERISA.

12.2 Restriction Against Assignment

The Company shall pay all amounts payable hereunder only to the person or persons designated by the Plan and not to any other person or entity. No right, title or interest in the Plan or in any account may be sold, pledged, assigned or transferred in any manner other than by will or the laws of descent and distribution. No right, title or interest in the Plan or in any benefit under the Plan shall be liable for the debts, contracts or engagements of the Participant or his successors in interest or shall be subject to disposition by transfer, alienation, anticipation, pledge, encumbrance, assignment or any other means whether such disposition be voluntary or involuntary or by operation of law by judgment, levy, attachment, garnishment or any other legal or equitable proceedings (including bankruptcy), and any attempted disposition thereof shall be null and void and of no effect, except to the extent that such disposition is permitted by the preceding sentence.

Notwithstanding the provisions of this subsection (B), a Participant’s benefit may be transferred pursuant to a domestic relations order that constitutes a “qualified domestic relations order” as defined by the Code or Title I of ERISA.

12.3 Withholding

There shall be deducted from each payment made under the Plan payable to the Participant (or beneficiary) all taxes which are required to be withheld by the Company in respect to such payment or this Plan. The Company shall have the right to reduce any payment (or compensation) by the amount of such of cash sufficient to provide the amount of said taxes.

12.4 Governing Law

This Plan shall be construed, governed and administered in accordance with the ERISA.

12.5 Receipt of Release

Any payment to a Participant or the Participant’s beneficiary in accordance with the provisions of the Plan shall, to the extent thereof, be in full satisfaction of all claims against the Compensation Committee and the Company. The Committee may require such Participant or Beneficiary, as a condition precedent to such payment, to execute a receipt and release to such effect prior to the payment date specified under the Plan.

12.6 Payments on Behalf of Persons Under Incapacity

In the event that any amount becomes payable under the Plan to a person who, in the sole judgment of the Compensation Committee, is considered by reason of physical or mental condition to be unable to give a valid receipt therefore, the Compensation Committee may direct that such payment be made to any person found by the Compensation Committee, in its sole judgment, to have assumed the care of such person. Any payment made pursuant to such termination shall constitute a full release and discharge of the Compensation Committee and the Company.

12.7 Notice

Any notice or filing required or permitted to be given to the Compensation Committee under the Plan shall be sufficient if in writing and hand delivered, or sent by registered or certified mail, to the principal office of the Company, directed to the attention of the General Counsel and Secretary of Sempra Energy. Such notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification.

12.8 Errors and Misstatements

In the event of any misstatement or omission of fact by a Participant to the Compensation Committee or any clerical error resulting in payment of benefits in an incorrect amount, the Compensation Committee shall promptly cause the amount of future payments to be corrected upon discovery of the facts and shall pay or, if applicable, cause the Plan to pay, the Participant or any other person entitled to payment under the Plan any underpayment in a lump sum or to recoup any overpayment from future payments to the Participant or any other person entitled to payment under the Plan in such amounts as the Compensation Committee shall direct or to proceed against the Participant or any other person entitled to payment under the Plan for recovery of any such overpayment

12.9 Pronouns and Plurality

The masculine pronoun shall include the feminine pronoun, and the singular the plural where the context so indicates.

12.10 Severability

In the event that any provision of the Plan shall be declared unenforceable or invalid for any reason, such unenforceability or invalidity shall not affect the remaining provisions of the Plan but shall be fully severable, and the Plan shall be construed and enforced as if such unenforceable or invalid provision had never been included herein.

12.11 Headings

Headings and subheadings in this Plan are inserted for convenience of reference only and are not to be considered in the construction of the provisions hereof.

Executed at San Diego, California this 8th day of June, 2009.

SEMPRA ENERGY

By:

Title: Sr. Vice President, Human Resources

Date: June 8, 2009

APPENDIX A

EARLY RETIREMENT REDUCTION FACTOR

Age Early Retirement Factor*

62 and later 100%

61 97

60 94

59 90

58 86

57 82

56 78

55 74

*Reduction factors vary by age and months.

APPENDIX B

GRANDFATHER BENEFIT

Current Participants in the Prior Plans are permanently grandfathered under the Prior Plan provisions if the benefit is greater.

Exhibit 10.29

FIRST AMENDMENT

TO THE

2009 AMENDMENT AND RESTATEMENT

OF THE

SEMPRA ENERGY

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

Sempra Energy maintains the Sempra Energy Supplemental Executive Retirement Plan, as amended and restated, effective as of July 1, 2009 (the “Plan”). In order to amend the Plan in certain respects, this First Amendment to the Plan is hereby adopted, effective as of February 11, 2010.

The Plan is hereby amended, as follows:

1. Section 2.3 of the Plan is hereby amended in its entirety to read as follows:

2.3 Spouse's Supplemental Retirement Benefit

The Surviving Spouse of a Participant who dies on or after his Retirement Date and who receives his Supplemental Retirement Benefit in the form of a straight life annuity is eligible for a Spouse's Supplemental Retirement Benefit in accordance with Sections 3.2 and 3.4. This Section 2.3 and Section 3.2 shall apply only in the case of a Participant who became a Participant prior to February 11, 2010.

2. The first paragraph of Section 3.1 of the Plan is hereby amended in its entirety to read as follows:

The Supplemental Retirement Benefit payable to a Participant in the form of a straight life annuity shall be determined as of his Retirement Date and shall be equal to (a) minus (b) with the resultant product multiplied by the Participant’s Vesting Factor and then the resultant product multiplied by the early retirement reduction (pursuant to Appendix A) for Retirement Dates which precede attainment of 62 years of age.

3. The introductory paragraph of Section 3.1(a) of the Plan is hereby amended in its entirety to read as follows:

(a)

is an annual amount equal to the sum of the following percent of the total of the Participant's Average Earnings and Average Bonus

4. The introductory paragraph of Section 3.1(b) of the Plan is hereby amended in its entirety to read as follows:

(b)

is an annual amount equal to the sum of

5. The last sentence of the introductory paragraph of Section 3.1(c) of the Plan is hereby amended in its entirety to read as follows:

Except as provided in paragraph (i) or (ii) below, the Participant’s Supplemental Retirement Benefit shall be paid in an Actuarial Equivalent lump sum.

6. Section 3.2 of the Plan is hereby amended in its entirety to read as follows:

3.2

Amount of Spouse's Supplemental Retirement Benefit for Certain Participants

(a)

The annual Spouse's Supplemental Retirement Benefit payable to a Surviving Spouse of a Participant who receives his Supplemental Retirement Benefit in the form of a straight life annuity is equal to 50% of the Participant's Supplemental Retirement Benefit as determined in accordance with Section 3.1(a) without the reduction in 3.1(b) but adjusted by the Vesting Factor and the early retirement reduction pursuant to Appendix A. The Spouse’s Supplemental Retirement Benefit shall be paid monthly, beginning on the last day of the month next following the month in which the death of the Participant occurs and will continue to be paid monthly during the life of the Surviving Spouse.

(b)

A Participant who receives his Supplemental Retirement Benefit in the form of a lump sum payment shall receive an additional lump sum payment equal to the Actuarial Equivalent value of the Spouse’s Supplemental Retirement Benefit (determined assuming that such Participant had elected to receive his Supplemental Retirement Benefit in the form of a straight life annuity). Such additional lump sum payment shall be paid on the payment date of his Post-Section 409A Supplemental Retirement Benefit in accordance with Section 3.4.

7. Section 3.4(a) of the Plan is hereby amended in its entirety to read as follows:

(a)

Subject to subsections (b), (c) and (d), a Participant’s Pre-Section 409A Supplemental Retirement Benefit will be paid as soon after the Participant's Retirement Date as is reasonably practicable, and a Participant’s Post-Section 409A Supplemental Retirement Benefit will be paid or commence upon such Participant’s Separation from Service (or such other commencement date as is determined under Section 3.1). If a straight life annuity payment is elected pursuant to Section 3.1, for purposes of the payment of such Participant’s Pre-Section 409A Supplemental Retirement Benefit, such Pre-Section 409A Supplemental Retirement Benefit will be paid monthly, beginning on the last day of the month of the Participant's Retirement Date and will continue to be paid monthly during the life of the Participant, the last payment to be made to the Participant’s spouse or, if none, to the Participant’s estate, on the last day of the month in which the death of the Participant occurs. If a straight life annuity payment is elected pursuant to Section 3.1, for purposes of the payment of such Participant’s Post-Section 409A Supplemental Retirement Benefit, such Post-Section 409A Supplemental Retirement Benefit will be paid monthly, beginning on the last day of the month of the Participant's Separation from Service (or such other commencement date as is determined under Section 3.1) and will continue to be paid monthly during the life of the Participant, the last payment to be made to the Participant’s spouse or, if none, to the Participant’s estate, on the last day of the month in which the death of the Participant occurs. If the Participant became a Participant prior to February 11, 2010 and elected a straight life annuity, the Surviving Spouse will receive the Spouse's Supplemental Retirement Benefit, which will be paid monthly, and will commence on the last day of the month following the month in which the Participant dies and will continue during the life of the Surviving Spouse. If the Participant elected a joint and survivor annuity, and the designated beneficiary survives the Participant, the designated beneficiary will receive the survivor benefit under the annuity elected by the Participant, which will be paid monthly, and will commence on the last day of the month following the month in which the Participant does and will continue during the life of the designated beneficiary. In all cases, the monthly benefit shall equal the annual benefit divided by 12.

8. The introductory paragraph of Section 5.1 of the Plan is hereby amended in its entirety to read as follows:

Executed at San Diego, California this 11th day of February, 2010.

SEMPRA ENERGY

By: _____________________________

Title:

Sr. Vice President, Human Resources

Date: February 11, 2010

Exhibit 10.31

THE

SEMPRA ENERGY

CASH BALANCE RESTORATION PLAN

(As Amended and Restated Effective as of November 10, 2015)

TABLE OF CONTENTS

BACKGROUND

PURPOSE

ADMINISTRATION

ELIGIBILITY; PARTICIPATION

AMOUNT OF BENEFITS

PAYMENT OF BENEFITS

EMPLOYEE’S RIGHTS

AMENDMENT AND DISCONTINUANCE

DEFINITIONS

10.

EMPLOYEES OF SEMPRA ENERGY TRADING CORPORATION AND SEMPRA ENERGY SOLUTIONS LLC

11.

SECTION 409A OF THE CODE

12.

CLAIMS PROCEDURE

13.

MISCELLANEOUS

1.	BACKGROUND

The Sempra Energy Excess Cash Balance Plan (the “Plan”) was effective as of July 1, 1998.

The Plan was amended and restated effective as of November 5, 2007. The name of the Plan was changed to the Sempra Energy Cash Balance Restoration Plan effective June 16, 2008.

The Plan was amended and restated effective as of July 1, 2009. Such amendment and restatement of the Plan provided that, for each Participant of the Plan who is also a participant in the SERP (as defined below), effective as of July 1, 2009 (or, in the case of a Participant who becomes a participant in the SERP after July 1, 2009, effective as of such Participant’s commencement of participation in the SERP), such Participant’s benefit under this Plan (if any) shall cease to be provided under this Plan and shall be transferred to and provided under the SERP. In the event that a Participant’s benefit under this Plan (if any) is transferred to the SERP, such benefit shall be paid under the SERP at the time and in the form of payment provided for such benefit under this Plan, as determined immediately prior to the transfer of such benefit to the SERP (subject to the terms and conditions of the SERP).

The following provisions constitute an amendment, restatement and continuation of the Plan as in effect immediately prior to November 10, 2015. This amendment and restatement of the Plan shall be effective as of November 10, 2015.

PURPOSE

This Plan serves two purposes. First, it provides benefits for certain Employees in excess of the limitations on benefits under the Basic Plan (as defined below) imposed by Section 415 of the Code (as defined below). The portion of the Plan providing these benefits is intended to be an “excess benefit plan” as defined in Section 3(36) of ERISA (as defined below). Second, it provides benefits for certain Employees in excess of the limitations on benefits under the Basic Plan imposed by Section 401(a) (17) of the Code.

3.	ADMINISTRATION

This Plan shall be administered by the Compensation Committee of Sempra Energy (“Compensation Committee”) in a manner consistent with the administration of the Basic Plan. However, the portion of this Plan which is an unfunded “excess benefit plan” as defined in Section 3(36) of ERISA shall be administered as such and is exempt from the provisions of Title I of ERISA pursuant to Section 4(b) (5) of ERISA, and the rest of this Plan shall be administered as an unfunded plan maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees. The Compensation Committee’s decisions in all matters involving the interpretation and application of this Plan shall be final. Sempra Energy’s Senior Human Resources Officer shall have discretionary authority with respect to administrative matters relating to this Plan, except when exercise of such authority would materially affect the cost of the Plan to the Company, materially increase benefits to Participants, or affect such Senior Human Resources Officer in a manner materially different from other Participants.

4.	ELIGIBILITY; PARTICIPATION

(A)

All Employees whose pension benefits under the Basic Plan are limited by the compensation and benefits limitations imposed by Sections 401(a)(17) and 415 of the Code shall be eligible for benefits under this Plan. In no event shall an Employee who is not entitled to benefits under the Basic Plan be eligible for a benefit under this Plan. An Employee who is a participant in the Basic Plan shall first become an Eligible Employee on the first date on which such Employee’s benefits under the Basic Plan are limited by the provisions of Section 415 of the Code, or such Employee’s benefits under the Basic Plan are limited by the covered compensation limitations of Section 401(a)(17) of the Code.

(B)	Except as provided in subsections (C) and (D), an Eligible Employee shall be a Participant and shall be entitled to benefits in accordance with Section 5.

(C)

Effective as of the Participant’s Transfer Date (if any), a Participant’s benefit under this Plan (determined immediately prior to the Participant’s Transfer Date) shall be transferred from this Plan to the SERP, and this Plan shall cease to provide such benefit to such Participant and the SERP shall thereafter provide such benefit to such Participant in lieu thereof. The transfer of such Participant’s benefit to the SERP shall be made in accordance with Section 409A of the Code and the Treasury Regulations thereunder and the time and form of payment of such benefit under the SERP (determined as of such Participant’s Transfer Date) shall be same as the time and form of payment of the Participant’s benefit under this Plan (determined immediately prior to such Participant’s Transfer Date).

(D)

Effective as of the Participant’s Transfer Date, the Participant shall cease to be a Participant in this Plan and no further benefits shall be paid to or in respect of such Participant under this Plan. In no event shall the Participant be paid a benefit under this Plan that duplicates any benefit paid under the SERP.

(E)	For purposes of subsections (C) and (D), a Participant’s “Transfer Date” shall be July 1, 2009 (if the Participant is then a participant in the SERP), or, if later, the date on which such Participant becomes a participant in the SERP.

5.	AMOUNT OF BENEFITS

The benefit payable to a Participant shall be determined under subsections (A) and (B), based on such benefits payable in the form of a straight life annuity with a cost of living adjustment feature unless one is provided under the Basic Plan.

(A)	415 Make-Up

The benefits payable under this subsection (A) to a Participant whose benefits under the Basic Plan are limited by the provisions of Section 415 of the Code incorporated in the Basic Plan, or to his beneficiary(ies), shall equal the excess, if any, of:

(i)	the benefits which would be paid to such Participant or on his behalf to his beneficiary(ies) under the Basic Plan, if the provisions of such Basic Plan were administered without regard to the benefit limitations under Section 415 of the Code set forth in the Basic Plan, over

(ii)	the benefits which are paid to such Participant or on his behalf to his beneficiary(ies) under the Basic Plan.

(B)	401(a) (17) Make-Up

The benefits payable under this subsection (B) to a Participant whose benefits under the Basic Plan are limited by the covered compensation limitations of Section 401(a)(17) of the Code incorporated in the Basic Plan, or to his beneficiary(ies), shall equal the excess, if any, of:

(i)

the benefits which would be paid to such Participant or on his behalf to his beneficiary(ies) under the Basic Plan, and, if applicable, to the Participant, under subsection (A), if the provisions of such Basic Plan were administered without regard to the covered compensation limitations under Section 401(a)(17) of the Code set forth in the Basic Plan (and, with respect to covered compensation paid or payable in plan years beginning on or after January 1, 2007, with a maximum compensation limit for each plan year of Two Million Dollars ($2,000,000)), over

(ii)	the benefits which are paid to such Participant or on his behalf to his beneficiary(ies) under the Basic Plan and, if applicable to the Participant, under subsection (A).

(C)	Conformance with Treasury Regulations

The benefits payable under subsections (A) and (B) are determined under the formula determining benefits under the Basic Plan, and the benefits payable under subsections (A) and (B) are determined as an amount offset by the benefits provided under the Basic Plan. The benefits payable under this Plan shall be determined in a manner consistent with Treasury Regulation Sections 1.409A-2(a)(9) and 1.409A-3(j)(5) (relating to nonqualified deferred compensation plans linked to qualified employer plans). Any amendment of the Basic Plan shall be taken into account under this Plan only to the extent permitted under Treasury Regulation Sections 1.409A-2(a)(9) and 1.409A-3(j)(5). Any reference to the interest and mortality factors (or actuarial methods and assumptions) specified in the Basic Plan shall mean the applicable interest and mortality factors (or actuarial methods or assumptions) specified under the terms of the Basic Plan as in effect on December 31, 2008.

6.	PAYMENT OF BENEFITS

(A)	Distribution Options for Certain SERP Participants

(i)	In the case of a Participant who is an Eligible Employee, and is a participant under the SERP (as defined below) as of December 31, 2005, the payment of benefits to such Participant under this Plan shall be made in accordance with this subsection (A).

(ii)

Unless the Participant exercises the Lump Sum Option and receives a lump sum distribution from the Basic Plan, the payment of such Participant’s Pre-Section 409A Benefit under this Plan shall be in the same payment form and at the same time as the payment of benefits to the Participant or on his behalf to his beneficiary(ies) under the Basic Plan. In the event a Participant receives a lump sum distribution from the Basic Plan, payment of such Participant’s Pre-Section 409A Benefit under this Plan will be made in the form of a straight life annuity. However, the Participant may request, in writing, payment of such Participant’s Pre-Section 409A Benefit under one of the following alternatives provided such request is filed with Sempra Energy at least three months prior to his Retirement Date or Termination under the Basic Plan:

(a)

The Participant may request payment of such Participant’s Pre-Section 409A Benefit under any of the other annuity options for which he is eligible under the Basic Plan. The amount of such optional annuity benefit with respect to his or her Pre-Section 409A Benefit under this Plan shall be computed as specified in Section 5 of this Plan using the interest and mortality factors specified in the Basic Plan. The request will be subject to approval of the Company’s Senior Human Resources Officer and, if approved, will be irrevocable as long as the Participant receives a lump sum distribution from the Basic Plan.

(b)

The Participant may request payment of such Participant’s Pre-Section 409A Benefit in a lump sum. The amount of the distribution with respect to his or her Pre-Section 409A Benefit under this Plan shall be computed as specified in Section 5 of this Plan using the actuarial factors specified in the Basic Plan. In the event such a request is timely filed, the request shall be considered by the Senior Human Resources Officer who shall have the sole discretion, considering the best interests of the Company, to allow a lump sum distribution. The decision of the Senior Human Resources Officer shall be final. The Participant will be required to show good reason for receiving a lump sum distribution and, file the request at least three months prior to separation from service as a condition of having the request approved. If the lump sum pay out is approved, the lump sum form of pay out shall be irrevocable even if the Participant changes his election under the Basic Plan.

The Participant’s beneficiary(ies) with respect to his or her Pre-Section 409A Benefit under this Plan shall be exactly the same as his beneficiary(ies) under the Basic Plan unless he elects and receives a lump sum distribution from the Basic Plan. In this event, the following provisions will apply if such Participant’s Pre-Section 409A Benefit under this Plan is paid in the form of a joint and survivor annuity.

The joint and survivor annuity is only available with respect to such Participant’s Pre-Section 409A Benefit if the Participant designates his or her spouse as beneficiary or obtains spousal consent to the designation of another beneficiary in the same manner as under the Basic Plan. If the spouse, or beneficiary dies before the Participant’s Retirement Date under the Basic Plan, the joint and survivor annuity with respect to such Participant’s Pre-Section 409A Benefit is canceled and the benefit is paid in the form of a straight life annuity.

(iii)

The payment of such Participant’s Post-Section 409A Benefit under this Plan shall be in a lump sum upon the Participant’s Separation from Service, unless the Participant elects to receive an optional annuity form of payment under subparagraph (a). The amount of the Participant’s lump sum distribution with respect to his Post-Section 409A Benefit under this Plan shall be computed as specified in Section 5 of this Plan using the actuarial factors specified in the Basic Plan.

(a)

The Participant may elect, in writing, payment commencing upon the Participant’s Separation from Service under any of the following annuity options: (I) a straight life annuity, (II) a joint and 50% survivor annuity, and (III) a joint and 100% survivor annuity. The amount of such optional annuity benefit with respect to such Participant’s Post-Section 409A Benefit under this Plan shall be computed as specified in Section 5 of this Plan using the interest and mortality factors specified in the Basic Plan. The election will be subject to approval of the Company’s Senior Human Resources Officer, in his or her discretion, and, if approved, will become effective and irrevocable on the date of such approval (except as provided in subsection (B)). The payment of such Participant’s Post-Section 409A Benefit in an annuity form shall commence upon the Participant’s Separation from Service.

(b)

A Participant’s election under subparagraph (a) may be made with respect to a Participant’s Post-Section 409A Benefit on or after January 1, 2006 and on or before December 31, 2008 in accordance with the transitional relief under Section 409A of the Internal Revenue Code and Internal Revenue Service Notices 2006-79 and 2007-86; provided, however, that a Participant’s election made in 2006 shall only apply with respect to payments that would not otherwise be payable in 2006, and shall not cause payments to be made in 2006 that would not otherwise be payable in 2006; and, provided, further, that a Participant’s election made in 2007 shall apply only with respect to payments that would not otherwise be payable in 2007 and shall not cause payments to be made in 2007 that would not otherwise be payable in 2007; and provided, further, that a Participant’s election made in 2008 shall apply only with respect to payments that would not otherwise be payable in 2008, and shall not cause payments to be made in 2008 that would not otherwise be payable in 2008. A Participant’s election under subparagraph (a) shall be considered made when the election becomes irrevocable. No election under subparagraph (a) may be made by a Participant unless such election becomes irrevocable on or prior to December 31, 2008.

(c)

The joint and survivor annuity is only available under clause (a)(II) or (III) if the Participant designates his or her spouse as beneficiary or obtains spousal consent to the designation of another beneficiary in the same manner as under the Basic Plan as part of the Participant’s election. If the spouse, or beneficiary dies before the Participant’s Separation from Service, the joint and survivor annuity is canceled and the benefit is paid in the form of a straight life annuity; provided, that the straight life annuity is actuarially equivalent, applying reasonable actuarial methods and assumptions, to the joint and survivor annuity in effect prior to such cancellation, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(d)	Except as provided in subsection (B), such Participant may not change the form and time of payment of such Participant’s Post-Section 409A Benefit under this Plan after December 31, 2008.

(iv)

Notwithstanding the foregoing, in no event shall a distribution option be available or apply to a Participant’s Pre-Section 409A Benefit if such distribution option would result in a material modification of the Participant’s Pre-Section 409A Benefit, as determined under Section 409A of the Code and Treasury Regulation Section 1.409A-6.

(v)

A lump sum payment of a Participant’s Post-Section 409A Benefit under this subsection (A) shall be paid on such date as is determined by Sempra Energy within thirty (30) days following the Participant’s Separation from Service. If an annuity payment is elected for purposes of the payment of such Participant’s Post-Section 409A Benefit under this subsection (A), such PostSection 409A Benefit shall be paid monthly, beginning on the last day of the month of the Participant’s Separation from Service and shall continue to be paid monthly during the life of the Participant and the life of the Participant’s designated beneficiary, if any (if such beneficiary survives the Participant). In all cases, the monthly benefit shall equal the annual benefit divided by 12.

(B)	Changes in Distribution Option for Certain SERP Participants

A Participant described in subsection (A) may elect to change the form of the payment of such Participant’s Post-Section 409A Benefit under this Plan, as follows:

(i)

The Participant may elect, in writing, to change the form of payment of such Participant’s Post Section 409A Benefit to any of the following options: (a) a lump sum, (b) a straight life annuity, (c) a joint and 50% survivor annuity, and (d) a joint and 100% survivor annuity. The amount of such optional benefit under this Plan shall be computed as specified in Section 5 of this Plan using the interest and mortality factors specified in the Basic Plan. The Participant’s election shall be subject to paragraphs (ii), (iii), (iv), (v), (vi) and (vii). Except as provided in paragraph (vi), the Participant’s election under this paragraph (i) shall be irrevocable. The joint and survivor annuity is only available under subparagraph (c) or (d) if the Participant designates his or her spouse as beneficiary or obtains spousal consent to the designation of another beneficiary in the same manner as under the Basic Plan as part of the Participant’s election. If the spouse, or beneficiary dies before the Participant’s Separation from Service, the joint and survivor annuity elected under this paragraph (i) is canceled and the benefit is paid in the form of a straight life annuity; provided, that the straight life annuity is actuarially equivalent, applying reasonable actuarial methods and assumptions, to the joint and survivor annuity in effect prior to such cancellation, as determined under Treasury Regulation Section 1.409A- 2(a)(2)(ii).

(ii)	The Participant’s election under paragraph (i) must be made prior to the Participant’s Separation from Service.

(iii)

If the Participant’s form of payment, as in effect at the time of election under paragraph (i), is an annuity, such Participant’s election under paragraph (i)(b), (c) or (d) (an election of an alternative annuity form of payment) shall be effective immediately and paragraph (v) shall not apply to such Participant’s election; provided, that the alternative annuity form of payment elected by the Participant is actuarially equivalent applying reasonable actuarial methods and assumptions to the annuity form of payment, as in effect at the time of the election, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(iv)

Except as provided in paragraph (iii), the Participant’s election under paragraph (i) shall not take effect until 12 months after his election is made, in accordance with Treasury Regulation Section 1.409A-2(b)(1)(i). If the Participant has a Separation from Service before the election under paragraph (i) becomes effective, the election under paragraph (i) shall terminate and the Participant’s Post-Section 409A Benefit shall be paid in the form of payment as in effect at the time of the election under paragraph (i).

(v)

Except as provided in paragraph (iii), in the event the Participant’s election under paragraph (i) becomes effective, the payment of such Participant’s Post-Section 409A Benefit under the option shall be deferred for a period of five years from the date such payment would otherwise have been paid (or, in the case of a life annuity treated as a single payment, five years from the date the first amount was scheduled to be paid), in accordance with Treasury Regulation Section 1.409A-2(b)(1)(ii).

(vi)

The Participant may elect to change the annuity option elected under paragraph (i) to another annuity option specified under paragraph (i) and such election shall become effective immediately, provided, that such change is made prior to the commencement of the payment of such Participant’s Post-Section 409A Benefit under this Plan; and, provided, further, that the annuity form of payment is actuarially equivalent, applying reasonable actuarial methods and assumptions, to the annuity form of payment, as in effect at the time of the election, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(vii)

Any change in a Participant’s form of payment under this subsection (B) shall be made in accordance with Treasury Regulation Section 1.409A-2(b).

(C)	Distribution Options for other Participants

Except as provided in subsection (A), in the case of a Participant who first became an Eligible Employee (as determined under Section 4) on or before December 31, 2005, the payment of benefits under this Plan shall be made in a lump sum in accordance with this subsection (C) upon the Participant’s Separation from Service, unless the Participant elects to receive an optional annuity form of payment under paragraph (i). The amount of the Participant’s lump sum distribution under this Plan shall be computed as specified in Section 5 of this Plan using the actuarial factors specified in the Basic Plan.

(i)

Such a Participant may elect, in writing, payment commencing upon the Participant’s Separation from Service under any of the following annuity options: (a) a straight life annuity, (b) a joint and 50% survivor annuity, and (c) a joint and 100% survivor annuity. The amount of such optional annuity benefit under this Plan shall be computed as specified in Section 5 of this Plan using the interest and mortality factors specified in the Basic Plan. The election will be subject to approval of the Senior Human Resources Officer of Sempra Energy, in his or her discretion, and, if approved, will become effective and irrevocable on the date of such approval (except as provided in subsection (D)). The payment of such Participant’s benefits under this Plan in an annuity form shall commence upon the Participant’s Separation from Service.

(ii)

A Participant’s election under paragraph (i) may be made with respect to such Participant’s benefit under this Plan on or after January 1, 2006 and on or before December 31, 2008 in accordance with the transitional relief under Section 409A of the Internal Revenue Code and Internal Revenue Service Notices 2006-79 and 2007-86; provided, however, that a Participant’s election made in 2006 shall apply only with respect to payments that would not otherwise be payable in 2006, and shall not cause payments to be made in 2006 that would not otherwise be payable in 2006; and, provided, further, that a Participant’s election made in 2007 shall apply only with respect to payments that would not otherwise be payable in 2007, and shall not cause payments to be made in 2007 that would not otherwise be payable in 2007; and provided, further, that a Participant’s election made in 2008 shall apply only with respect to payments that would not otherwise be payable in 2008, and shall not cause payments to be made in 2008 that would not otherwise be payable in 2008. A Participant’s election under paragraph (i) shall be considered made when the election becomes irrevocable. No election under paragraph (i) may be made by a Participant unless such election becomes irrevocable on or prior to December 31, 2008.

(iii)

The joint and survivor annuity is only available under subparagraphs (i)(b) or (c) if the Participant designates his or her spouse as beneficiary or obtains spousal consent to the designation of another beneficiary in the same manner as under the Basic Plan as part of the Participant’s election. If the spouse, or beneficiary dies before the Participant’s Separation from Service, the joint and survivor annuity is canceled and the benefit is paid in the form of a straight life annuity; provided, that the straight life annuity is actuarially equivalent, applying reasonable actuarial methods and assumptions, to the joint and survivor annuity in effect prior to such cancellation, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(iv)	Except as provided in subsection (D), such Participant may not change the form and time of payment of benefits under this Plan after December 31, 2008.

(v)

A lump sum payment under this subsection (C) shall be paid on such date as is determined by Sempra Energy within thirty (30) days following the Participant’s Separation from Service. An annuity under this subsection (C) shall be paid monthly, beginning on the last day of the month of the Participant’s Separation from Service and shall continue to be paid monthly during the life of the Participant and the life of the Participant’s designated beneficiary, if any (if such beneficiary survives the Participant). In all cases, the monthly benefit shall equal the annual benefit divided by 12.

(D)	Changes in Distribution Option for other Participants

A Participant described in subsection (C) may elect to change the form of the payment of such Participant’s benefit under this Plan, as follows:

(i)

The Participant may elect, in writing, to change the form of payment of such Participant’s benefit to any of the following options: (a) a lump sum, (b) a straight life annuity, (c) a joint and 50% survivor annuity, and (d) a joint and 100% survivor annuity. The amount of such optional benefit under this Plan shall be computed as specified in Section 5 of this Plan using the interest and mortality factors specified in the Basic Plan. The Participant’s election shall be subject to paragraphs (ii), (iii), (iv), (v), (vi) and (vii). Except as provided in paragraph (vi), the Participant’s election under this paragraph (i) shall be irrevocable. The joint and survivor annuity is only available under subparagraph (c) or (d) if the Participant designates his or her spouse as beneficiary or obtains spousal consent to the designation of another beneficiary in the same manner as under the Basic Plan as part of the Participant’s election. If the spouse, or beneficiary dies before the Participant’s Separation from Service, the joint and survivor annuity is canceled and the benefit is paid in the form of a straight life annuity; provided, that the straight life annuity is actuarially equivalent, applying reasonable actuarial methods and assumptions, to the joint and survivor annuity in effect prior to such cancellation, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(ii)	The Participant’s election under paragraph (i) must be made prior to the Participant’s Separation from Service.

(iii)

If the Participant’s form of payment, as in effect at the time of the election under paragraph (i), is an annuity, such Participant’s election under paragraph (i)(b), (c) or (d) (an election of an alternative annuity form of payment) shall be effective immediately and paragraph (v) shall not apply to such Participant’s election; provided, that the alternative annuity form of payment elected by the Participant is actuarially equivalent applying reasonable actuarial methods and assumptions to the annuity form of payment, as in effect at the time of the election, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(iv)

(v)

Except as provided in paragraph (iii), in the event the Participant’s election under paragraph (i) becomes effective, the payment of such Participant’s benefit under the option shall be deferred for a period of five years from the date such payment would otherwise have been paid (or, in the case of a life annuity treated as a single payment, five years from the date the first amount was scheduled to be paid), in accordance with Treasury Regulation Section 1.409A-2(b)(1)(ii).

(vi)

The Participant may elect to change an annuity form of payment elected under paragraph (i) to another annuity form of payment specified under paragraph (i)(b), (c) or (d), and such election shall be effective immediately; provided, that such change is made prior to the commencement date of the payment of benefits under this Plan; and, provided, further, that the annuity form of payment is actuarially equivalent applying reasonable actuarial methods and assumptions to the annuity form of payment, as in effect at the time of the election, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(vii)

Any change in a Participant’s form of payment under this subsection (D) shall be made in accordance with Treasury Regulation Section 1.409A-2(b).

(E)	Pre-Section 409A Benefit; Post-Section 409A Benefit.

(i)

In the case of a Participant described in subsection (A), such Participant’s “Pre-Section 409A Benefit” means the portion of such Participant’s benefit under the Plan, if any, to which such Participant had a legal binding right, and which was earned and vested, as of December 31, 2004, determined in accordance with Section 409A of the Code and Treasury Regulation Section 1.409A-6. Such Participant’s “Pre-Section 409A Benefit” shall be determined by the terms of the Plan and the Basic Plan, as in effect as of October 3, 2004.

Such Participant’s “Pre-Section 409A Benefit” shall equal the present value of the amount to which such Participant would have been entitled under the Plan if such Participant voluntarily terminated services without cause on December 31, 2004, and received a payment of the benefits available from the Plan on the earliest possible date allowed under the Plan to receive a payment of benefits following the termination of services, and received the benefits in the form with maximum value. Notwithstanding the foregoing, for any subsequent taxable year of such Participant, the “Pre-Section 409A Benefit” shall increase to equal the present value of the benefit such Participant actually becomes entitled to, in the form and at the time actually paid, determined under the terms of the Plan (including applicable limits under the Code), as in effect on October 3, 2004, without regard to any further services rendered by such Participant after December 31, 2004, or any other events affecting the amount of or the entitlement to benefits (other than such Participant’s election with respect to the time or form of an available benefit). Such present value shall be computed using the applicable actuarial assumptions and methods under the Basic Plan to the extent in accordance with Treasury Regulation Section 1.409A-6(a)(3)(i), or such other reasonable actuarial assumptions and methods as are permitted under Treasury Regulation Section 1.409A-6(a)(3)(i).

(ii)

In the case of a Participant described in subsection (A), such Participant’s “Post-Section 409A Benefit” means such Participant’s benefit under this Plan, less such Participant’s Pre-Section 409A Benefit (if any). In the case of any other Participant, such Participant’s “Post-Section 409A Benefit” means such Participant’s benefit under this Plan.

(F)	Distributions to Newly Eligible Employees

(i)

In the case of a Participant who first becomes an Eligible Employee under this Plan (as determined under Section 4) after December 31, 2005, the payment of benefits under this Plan shall be made in a lump sum in accordance with this subsection (F) upon the Participant’s Separation from Service, except as provided in paragraph (ii).

(ii)	The Participant may elect to change the form of the payment of benefits under this Plan, as follows:

(a)

The Participant may elect, in writing, to change the form of payment of such benefit to any of the following annuity options: (I) a straight life annuity, (II) a joint and 50% survivor annuity, and (III) a joint and 100% survivor annuity. The amount of such optional annuity benefit under this Plan shall be computed as specified in Section 5 of this Plan using the interest and mortality factors specified in the Basic Plan. The Participant’s election shall be subject to subparagraphs (b), (c), (d), (e) and (d). Except as provided in subparagraph (e), the Participant’s election under this subparagraph (a) shall be irrevocable. The joint and survivor annuity is only available under clause (II) or (III) if the Participant designates his or her spouse as beneficiary or obtains spousal consent to the designation of another beneficiary in the same manner as under the Basic Plan as part of the Participant’s election. If the spouse, or beneficiary dies before the Participant’s Separation from Service, the joint and survivor annuity is canceled and the benefit is paid in the form of a straight life annuity; provided, that the straight life annuity is actuarially equivalent, applying reasonable actuarial methods and assumptions, to the joint and survivor annuity in effect prior to such cancellation, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(b)	The Participant’s election under subparagraph (a) must be made prior to the Participant’s Separation from Service.

(c)

The Participant’s election under subparagraph (a) shall not take effect until 12 months after his election is made in accordance with Treasury Regulation Section 1.409A-2(b)(1)(i). If the Participant has a Separation from Service before the election under subparagraph (a) becomes effective, the election under subparagraph (a) shall terminate and the Participant’s benefit shall be paid in a lump sum payment under paragraph (i).

(d)

In the event the Participant’s election under subparagraph (a) becomes effective, the payment of benefits under the annuity option shall be deferred for a period of five years from the date such payment would otherwise have been paid (or, in the case of a life annuity treated as a single payment, five years from the date the first amount was scheduled to be paid), in accordance with Treasury Regulation Section 1.409A- 2(b)(1)(ii).

(e)

The Participant may elect to change the annuity form of payment elected under subparagraph (a) to another annuity form of payment specified under subparagraph (a) and such election shall be effective immediately; provided, that such change is made prior to the commencement of the payment of benefits under this Plan; and, provided, further, that the annuity form of payment is actuarially equivalent applying reasonable actuarial methods and assumptions to the annuity form of payment, as in effect at the time of the election, as determined under Treasury Regulation Section 1.409A-2(b)(2)(ii).

(f)	Any change in a Participant’s form of payment under this paragraph (ii) shall be in accordance with Treasury Regulation Section 1.409A-2(b).

(iii)

A lump sum payment under paragraph (F)(i) shall be paid on such date as is determined by Sempra Energy within thirty (30) days following the Participant’s Separation from Service. An annuity under this subsection (F) shall be paid monthly, beginning on the last day of the month in which the date determined under subparagraph (F)(ii)(d) occurs and shall continue to be paid monthly during the life of the Participant and the life of the Participant’s designated beneficiary, if any (if such beneficiary survives the Participant). In all cases, the monthly benefit shall equal the annual benefit divided by 12.

(G)	Death Benefits

If a Participant dies prior to the commencement of benefits under this Plan on or after his or her Separation from Service (or, in the case of a Participant described in subsection (A), such Participant’s Pre-Section 409A Death Benefit (if any), prior to the commencement of benefits under this Plan on or after such Participant’s Retirement Date or Termination), the payment of death benefits to such Participant’s beneficiary(ies) shall be made in accordance with this subsection (G).

(i)	The death benefits payable to such Participant’s beneficiary(ies) under this subsection (G) shall be computed as specified in Section 5 of this Plan using the actuarial factors specified in the Basic Plan.

(ii)	The death benefits payable to such Participant’s beneficiary(ies) under this subsection (G) shall be in lieu of any benefits that would have been payable under the other provisions of this Section 6, if such Participant had survived until the date of commencement of benefits.

(iii)

The death benefits payable to such Participant’s beneficiary(ies) under this subsection (G) shall be payable in a lump sum payment on such date as is determined by Sempra Energy during the thirty (30) day period commencing upon such Participant’s death; provided, however, that, in the case of a Participant described in subsection (A), such Participant’s PreSection 409A Death Benefit (if any) shall be paid in the same payment form and at the same time as the payment of pre-commencement death benefits on behalf of such Participant under the Basic Plan and such Participant’s Post-Section 409A Death Benefit shall be payable in a lump sum on such date as is determined by Sempra Energy during the thirty (30) day period commencing upon such Participant’s death.

(iv)	For purposes of this subsection (G) and Section 9,

(a)

in the case of a Participant described in subsection (A), such Participant’s “Pre-Section 409A Death Benefit” means the portion of the death benefits payable to such Participant’s beneficiary(ies) under this subsection (G), if any, to which such Participant had a legal binding right, and which was earned and vested, as of December 31, 2004, determined in accordance with Section 409A of the Code and Treasury Regulation Section 1.409A-6. Such Participant’s “Pre-Section 409A Death Benefit” shall be determined by the terms of the Plan and the Basic Plan, as in effect as of October 3, 2004 and in a manner consistent with paragraph (E)(i) and Treasury Regulation Section 1.409A-6(a)(3)(i), and

(b)	in the case of a Participant described in subsection (A), such Participant’s “Post Section 409A Death Benefit” means the death benefit payable to such Participant’s beneficiary(ies) under this subsection (G), less such Participant’s Pre-Section 409A Death Benefit.

(H)	Mandatory Distribution

Notwithstanding subsections (A), (B), (C), (D) and (F), if the actuarial value of a Participant’s benefit hereunder as of the date of the Participant’s Separation from Service is less than $10,000, the benefit shall be distributed in a lump sum upon the Participant’s Separation from Service in accordance with Treasury Regulation Section 1.409A-3(j)(4)(v). Such lump sum payment shall be paid on such date as is determined by Sempra Energy within thirty (30) days following the Participant’s Separation from Service. Such lump sum payment shall be made only if such payment satisfies the requirement of Treasury Regulation Section 1.409A-3(j)(4)(v)(A).

(I)	Distributions to Specified Employees

Notwithstanding the foregoing, in the case of a Participant who is a Specified Employee on the date of such Participant’s Separation from Service, the payment of such Participant’s Post-Section 409A Benefit to such Participant shall not be made before the date which is six months after the date of such Participant’s Separation from Service (or, if earlier, the date such Participant’s death) in accordance with Section 409A(a)(2)(B)(i) of the Code and the Treasury Regulations thereunder. Any payment of such Participant’s Post-Section 409A Benefit to which such Participant otherwise would have been entitled during the first six months following the date of such Participant’s Separation from Service shall be accumulated (with interest at the annual rate of interest on 30-year Treasury securities for the November next preceding the first day of the calendar year in which such Participant’s Separation from Service occurs) and paid on the first day of the seventh month following the date of such Participant’s Separation from Service (or, if earlier, the date of such Participant’s death) in accordance with Section 409A(a)(2)(B)(i) and the Treasury Regulations thereunder.

(J)	Prohibition on Acceleration of Distributions

The time or schedule of payment of any payment of a Participant’s Post-Section 409A Benefit under the Plan shall not be subject to acceleration, except as provided under Treasury Regulations promulgated in accordance with Section 409A(a)(3) of the Code.

(K)	Conformance of Time and Form of Payment under the SERP

(i)

If a Participant is or becomes a participant in the SERP, the payment of such Participant’s “Post-Section 409A Supplemental Retirement Benefit” (as defined in the SERP) to such Participant under the SERP shall be made or commence on the date of the payment or commencement of such Participant’s Post-Section 409A Benefit under this Plan, and the form of payment of such Participant’s “Post-Section 409A Supplemental Retirement Benefit” (as defined in the SERP) under the SERP shall be the same as the form of payment of such Participant’s Post-Section 409A Benefit under this Plan.

(ii)

In the event that a Participant elects to change the form of the payment of such Participant’s Post-Section 409A Benefit under this Plan, such Participant shall be deemed to have elected to change the form of the payment of such Participant’s “Post-Section 409A Supplemental Retirement Benefit” (as defined in the SERP) under the SERP to the form of the payment of such Participant’s Post-Section 409A Benefit under this Plan. Any such election shall be subject to the provisions of subsection (B), (D) or (F), as applicable, and the provisions of the SERP and, in any event, the time and form of payment of such Participant’s “Post-Section 409A Supplemental Retirement Benefit” under the SERP shall be the same as the time and form of payment of such Participant’s Post-Section 409A Benefit under this Plan.

(L)	Transfer Date

Subsections (A) through (K) shall apply prior to a Participant’s Transfer Date (if any).

7.	EMPLOYEE’S RIGHTS

An Employee shall not be entitled to any payments from the Basic Plan on the basis of any benefits to which he may be entitled under this Plan. Benefits under this Plan shall be payable only from the general assets of the Company.

8.	AMENDMENT AND DISCONTINUANCE

The Company expects to continue this Plan indefinitely, but reserves to the Compensation Committee the right to amend or discontinue the Plan if, in the Compensation Committee’s sole judgment, such a change is deemed necessary or desirable. However, if the Compensation Committee shall amend or discontinue this Plan, the Company shall be liable for any benefits accrued under this Plan as of the date of such amendment or termination determined on the basis of each employee’s presumed termination of employment as of such date. Provided further, that if the Department of Labor determines, or issues regulations under which, the Plan would be subject to Parts 2 and/or 3 of Title I of ERISA, the Compensation Committee may take such action or actions as it deems appropriate. Such actions may include, but are not limited to, modification, termination or partial termination of the Plan. In the event of such modification, termination, or partial termination, the Compensation Committee may make immediate distribution of the benefits of some or all of the Participant’s benefits, as it deems necessary or appropriate, to the extent such distribution is in accordance with Section 409A of the Code and the Treasury Regulations thereunder.

9.	DEFINITIONS

“Basic Plan” means the Sempra Energy Cash Balance Plan or, where applicable by the context, the pension plan of a member of a controlled group of corporations (within the meaning of Section 414(b) of the Code) of which Sempra Energy is a member or two or more trades or businesses (whether or not incorporated) under common control (within the meaning of Section 414(c) of the Code) with Sempra Energy, as such plan is amended from time to time; provided, however, that the term “Basic Plan” shall not include The Retirement Plan for Employees of EnergySouth, Inc. and Affiliates.

“Code” means the Internal Revenue Code of 1986, as amended from time to time, and all applicable rules and regulations thereunder.

“Company” means Sempra Energy and any successor corporation. “Company” shall also include each corporation which is a member of a controlled group of corporations (within the meaning of Section 414(b) of the Code) of which Sempra Energy is a member or two or more trades or businesses (whether or not incorporated) under common control (within the meaning of Section 414(c) of the Code) with Sempra Energy, if such corporation or trade or business maintains or is a participating employer in a Basic Plan for the benefit of its employees and the Compensation Committee provides that such corporation or trade or business shall participate in the Plan and such entity’s governing body adopts the Plan. Any corporation or trade or business which participates in the Plan immediately prior to the Effective Date shall be deemed to participate in the Plan and to have adopted the Plan without any further action of either such entity or Sempra Energy, subject to the terms and conditions of the Plan.

“Effective Date” means November 10, 2015.

“Eligible Employee” means an Employee who has become eligible for benefits under the Plan, as determined in Section 4.

“Employee” means an individual who is an employee of the Company.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time.

“Lump Sum Option” shall have the meaning of the lump sum distribution option as described in the Basic Plan.

“Retirement Date” shall have the meaning set forth in the Basic Plan.

“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).

Effective as of January 1, 2008, and in accordance with Treasury Regulation Section 1.409A-1(h)(3) (and the transitional relief under Internal Revenue Service Notice 2005-1, the proposed regulations under Section 409A of the Code and Internal Revenue Service Notice 2006-79), and in connection with the formation of RBS Sempra Commodities (as defined in Section 10), with respect to the benefits payable under this Plan to a Participant who is an employee of SET LLC or SES (each, as defined in Section 10), and who is a Transferred Employee (as defined in Section 10), the foregoing definition of “Separation from Service” shall be applied by determining the “service recipient,” as defined in Treasury Regulation Section 1.409A-1(g), by substituting the language “at least 20%” for the language “at least 80%” and applying Sections 1563(a)(1), (2) and (3) for purposes of determining a controlled group of corporations under Section 414(b) of the Code and in applying Treasury Regulation Section 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Section 414(c) of the Code. This paragraph shall not apply with respect to the benefits payable under this Plan to any other Participant.

“SERP” means the Sempra Energy Supplemental Executive Retirement Plan, as amended from time to time.

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

“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).

“Termination” shall have the meaning set forth in the Basic Plan.

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

10.	EMPLOYEES OF SEMPRA ENERGY TRADING CORPORATION AND SEMPRA ENERGY SOLUTIONS LLC

This Section 10 includes special provisions relating to the benefits of the Participants who are employed by Sempra Energy Trading Corporation (“SET”) and Sempra Energy Solutions LLC (“SES”).

(A)	Background

SET and SES maintain the Basic Plan for the benefit of their respective eligible employees. Certain SET and SES employees are Participants in this Plan.

On July 9, 2007, Sempra Energy, Sempra Global, Sempra Energy Trading International, B.V. (“SETI”) and The Royal Bank of Scotland pie (“RBS”) entered into the Master Formation and Equity Interest Purchase Agreement, dated as of July 9, 2007 (the “Master Formation Agreement”), which provides for the formation of a partnership, RBS Sempra Commodities LLP (“RBS Sempra Commodities”), to purchase and operate Sempra Energy’s commodity-marketing businesses. Pursuant to a Master Formation Agreement, RBS Sempra Commodities will be formed as a United Kingdom limited liability partnership and RBS Sempra Commodities will purchase Sempra Energy’s commodity-marketing subsidiaries.

Prior to the Closing, SET will be converted into a limited liability company (“SET LLC”). Following such conversion, SET employees will be employed by SET LLC. Prior to the Closing, SES will become a wholly-owned subsidiary of SET LLC.

Also, prior to the Closing, Sempra Energy will own, directly or indirectly through wholly-owned subsidiaries, 100% of the membership interests in SET LLC and SES. Prior to the Closing, SET LLC and SES will be disregarded entities for federal income tax purposes.

Effective as of the Closing, RBS Sempra Commodities will purchase 100% of the membership interests in SET LLC.

As provided in the Master Formation Agreement, an employee of SET LLC who is actively at work on the Closing Date will continue to be employed by SET LLC immediately after the Closing Date, and an employee of SES who is actively at work on the Closing Date will continue to be employed by SES (each such employee is referred to as a Transferred Employee).

Also, as provided in the Master Formation Agreement, with respect to an employee of SET LLC or SES who is not actively at work on the Closing Date because such employee is on approved short term disability or long-term disability leave in accordance with the Sempra Plans (such employee is referred to as an Inactive Employee), if such Inactive Employee returns to active work at the conclusion of such leave, and in any case within six months following the Closing Date (or such longer period as is required by applicable law), such Inactive Employee shall become a Transferred Employee as of the date of such person’s return to active employment with the SET LLC or SES (such date is referred to as the Transfer Date).

Effective as of the Closing, SET LLC will be a wholly-owned subsidiary of RBS Sempra Commodities, SES will be an indirect, wholly-owned subsidiary of RBS Commodities, Sempra Global and SETI will be partners in RBS Sempra Commodities, and Sempra Energy will own, indirectly through wholly-owned subsidiaries, at least a 50% profits interest in RBS Sempra Commodities.

(B)	Cessation of Participation by SET LLC and SES; Cessation of Benefit Accruals

(i)	Prior to the Closing, SET LLC shall be a participating employer in this Plan. Effective as of the Closing Date, SET LLC will cease to be a participating employer in this Plan.

(ii)	Prior to the Closing, SES shall be a participating employer in this Plan. Effective as of the Closing Date, SES will cease to be a participating employer in this Plan.

(iii)

Effective as of the Closing Date (or the Transfer Date, if applicable), a Transferred Employee who is a Participant shall cease to accrue any further benefits as an active participant in this Plan and shall have no rights to continue as an active participant under this Plan (without derogation of the rights of such Transferred Employee as a vested, terminated Participant in this Plan).

(iv)	No Transferred Employee shall become a Participant on or after the Closing Date.

(C)	Separation from Service

(i)

Effective as of the Closing, RBS Sempra Commodities will be a member of a group of trades or businesses (whether or not incorporated) under common control for purposes of Section 414(c) of the Code and Treasury Regulation Section 1.414(c)-2, as determined under Treasury Regulation Section 1.409A-1(h)(3), that includes Sempra Energy and its wholly-owned subsidiaries. Consequently, effective as of the Closing, RBS Sempra Commodities will be included in the “service recipient” that includes Sempra Energy and its wholly-owned subsidiaries, as defined under Treasury Regulation Section 1.409A-1(h)(3).

(ii)	A Participant who is an employee of SET LLC or SES, and who is a Transferred Employee effective as of the Closing Date, will not have a Separation from Service solely as a result of the purchase of the membership interests of SET LLC by RBS Sempra Commodities effective as of the Closing.

(iii)

A Participant who is an employee of SET LLC or SES, who is an Inactive Employee, and who becomes a Transferred Employee effective on a Transfer Date after the Closing Date, will not have a Separation from Service solely as a result of the purchase of the membership interests of SET LLC by RBS Sempra Commodities or becoming a Transferred Employee on a Transfer Date after the Closing Date.

(iv)

For purposes of the Plan, a Participant who is an employee of SET LLC or SES, and who is or becomes a Transferred Employee, will have a Separation from Service on or after the Closing Date (or the Transfer Date, if applicable), as determined under Section 10 and Treasury Regulation Section 1.409A-1(h).

(D)	Certain Defined Terms

For purposes of this Section 10, the terms “Closing,” “Closing Date,” “Inactive Employee,” “Sempra Plans,” “Transferred Employees” and “Transfer Date” shall have the meanings ascribed to such terms under the Master Formation Agreement.

11.	SECTION 409A OF THE CODE

(A)

(B)

The Plan provides that benefits under the Plan are determined under the formula for determining benefits under the Basic Plan (which is a qualified employer plan, as defined in Treasury Regulation Section 1.409A-1(a)(2)), applied without regard to the limitations applicable to the Basic Plan under Sections 401(a)(17) and 415 of the Code, and after an offset of the benefits provided under the Basic Plan. Accordingly, the Plan is intended to be a nonqualified deferred compensation plan subject to Treasury Regulation Sections 1.409A-2(a)(9) and 1.409A-3(j)(5).

12.	CLAIMS PROCEDURE

(A)

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 Compensation Committee, setting forth his claim. The request must be addressed to the Compensation 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 (if any), provided that such Participant, beneficiary or person has submitted a written notice evidencing the authority of such representative to the Compensation Committee.

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

(B)	Claim Decision

(C)	Request for Review

Within 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 Compensation Committee of Sempra Energy, at its 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 Compensation 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 Compensation Committee’s initial determination with respect to the claim.

(D)	Review of Decision

The Compensation 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.

13.	MISCELLANEOUS

(A)	Unsecured General Creditor

(B)	Restriction Against Assignment

Notwithstanding the provisions of this subsection (8), a Participant’s benefit may be transferred pursuant to a domestic relations order that constitutes a “qualified domestic relations order” as defined by the Code or Title I of ERISA.

(C)	Withholding

(D)	Governing Law

This Plan shall be construed, governed and administered in accordance with the ERISA and, to the extent not preempted by ERISA, the laws of the State of California (without regard to the conflicts of laws principles thereof).

(E)	Receipt of Release

(F)	Payments on Behalf of Persons Under Incapacity

(G)	Limitation of Rights

Neither the establishment of the Plan nor any modification thereof, nor the creating of any fund or account, nor the payment of any benefits shall be construed as giving to any Participant or other person any legal or equitable right against the Company except as provided in the Plan. In no event shall the terms of employment of any Participant be modified or in any way be effected by the provisions of the Plan.

(H)

Notice

(I)	Errors and Misstatements

(J)	Pronouns and Plurality

The masculine pronoun shall include the feminine pronoun, and the singular the plural where the context so indicates.

(K)	Severability

(L)

Headings

Headings and subheadings in this Plan are inserted for convenience of reference only and are not to be considered in the construction of the provisions hereof.

Executed at San Diego, California this 10th day of November, 2015.

SEMPRA ENERGY

By: __________________________

G. Joyce Rowland

Title: Senior Vice President,

Chief Human Resources and

Administrative Officer

Exhibit 10.63

SEMPRA ENERGY

SEVERANCE PAY AGREEMENT

THIS AGREEMENT (this “Agreement”), dated as of August 4, 2012, (the “Effective Date”) is made by and between SEMPRA ENERGY, a California corporation (“Sempra Energy”), and Bruce Folkmann (the “Executive”).

WHEREAS, the Executive is currently employed by Sempra Energy or a direct or indirect subsidiary of Sempra Energy (Sempra Energy and its subsidiaries are hereinafter collectively referred to as the “Company”) as Vice President and Controller, USG&P; and

WHEREAS, Sempra Energy and the Executive desire to enter into this Agreement; and

WHEREAS, the Board of Directors of Sempra Energy (the “Board”) has authorized this Agreement.

NOW, THEREFORE, in consideration of the premises and mutual covenants herein contained, the Company and the Executive hereby agree as follows:

Section 1. Definitions

. For purposes of this Agreement, the following capitalized terms have the meanings set forth below:

“Accounting Firm” has the meaning assigned thereto in Section 9(b) hereof.

“Act” has the meaning assigned thereto in Section 2 hereof.

“Additional Post-Change in Control Severance Payment” has the meaning assigned thereto in Section 6(a) hereof.

“Affiliate” has the meaning set forth in Rule 12b-2 promulgated under the Exchange Act.

“Annual Base Salary” means the Executive’s annual base salary from the Company.

“Asset Purchaser” has the meaning assigned thereto in Section 16(e).

“Asset Sale” has the meaning assigned thereto in Section 16(e).

“Average Annual Bonus” means the average of the annual bonuses from the Company earned by the Executive with respect to the three (3) fiscal years of the Company immediately preceding the Date of Termination (the “Bonus Fiscal Years”); provided, however, that, if the Executive was employed by the Company during all or any portion of one or two of the Bonus Fiscal Years (but not three of the Bonus Fiscal Years), “Average Annual Bonus” means the average of the annual bonuses (if any) from the Company earned by the Executive with respect to the Bonus Fiscal Years during all or any portion of which the Executive was employed by the Company; and, provided, further, that, if the Executive was not employed by the Company during all or any portion of any of the Bonus Fiscal Years, “Average Annual Bonus” means zero.

“Beneficial Owner” has the meaning set forth in Rule 13d-3 promulgated under the Exchange Act.

“Cause” means:

(a) Prior to a Change in Control, (i) the willful failure by the Executive to substantially perform the Executive’s duties with the Company (other than any such failure resulting from the Executive’s incapacity due to physical or mental illness, (ii) the grossly negligent performance of such obligations referenced in clause (i) of this definition, (iii) the Executive’s gross insubordination; and/or (iv) the Executive’s commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty. For purposes of clause (i) of this subsection (a), no act, or failure to act, on the Executive’s part shall be deemed “willful” unless done, or omitted to be done, by the Executive not in good faith and without reasonable belief that the Executive’s act, or failure to act, was in the best interests of the Company.

(b) From and after a Change in Control, (i) the willful and continued failure by the Executive to substantially perform the Executive’s duties with the Company (other than any such failure resulting from the Executive’s incapacity due to physical or mental illness or any such actual or anticipated failure after the issuance of a Notice of Termination for Good Reason by the Executive pursuant to Section 3 hereof) and/or (ii) the Executive’s commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty. For purposes of clause (i) of this subsection (b), no act, or failure to act, on the Executive’s part shall be deemed “willful” unless done, or omitted to be done, by the Executive not in good faith and without reasonable belief that the Executive’s act, or failure to act, was in the best interests of the Company. Notwithstanding the foregoing, the Executive shall not be deemed terminated for Cause pursuant to clause (i) of this subsection (b) unless and until the Executive shall have been provided with reasonable notice of and, if possible, a reasonable opportunity to cure the facts and circumstances claimed to provide a basis for termination of the Executive’s employment for Cause.

“Change in Control” shall be deemed to have occurred on the date that a change in the ownership of Sempra Energy, a change in the effective control of Sempra Energy, or a change in the ownership of a substantial portion of assets of Sempra Energy occurs (each, as defined in subsection (a) below), except as otherwise provided in subsections (b), (c) and (d) below:

(a) (i) a “change in the ownership of Sempra Energy” occurs on the date that any one person, or more than one person acting as a group, acquires ownership of stock of Sempra Energy that, together with stock held by such person or group, constitutes more than fifty percent (50%) of the total fair market value or total voting power of the stock of Sempra Energy,

(ii) a “change in the effective control of Sempra Energy” occurs only on either of the following dates:

(A) the date any one person, or more than one person acting as a group, acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of Sempra Energy possessing thirty percent (30%) or more of the total voting power of the stock of Sempra Energy, or

(B) the date a majority of the members of the Board is replaced during any twelve (12) month period by directors whose appointment or election is not endorsed by a majority of the members of the Board before the date of appointment or election, and

(iii) a “change in the ownership of a substantial portion of assets of Sempra Energy” occurs on the date any one person, or more than one person acting as a group, acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by such person or persons) assets from Sempra Energy that have a total gross fair market value equal to or more than eighty-five percent (85%) of the total gross fair market value of all of the assets of Sempra Energy immediately before such acquisition or acquisitions.

(b) A “change in the ownership of Sempra Energy” or “a change in the effective control of Sempra Energy” shall not occur under clause (a)(i) or (a)(ii) by reason of any of the following:

(i) an acquisition of ownership of stock of Sempra Energy directly from Sempra Energy or its Affiliates other than in connection with the acquisition by Sempra Energy or its Affiliates of a business,

(ii) a merger or consolidation which would result in the voting securities of Sempra Energy outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof), in combination with the ownership of any trustee or other fiduciary holding securities under an employee benefit plan of the Company, at least sixty percent (60%) of the combined voting power of the securities of Sempra Energy or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation, or

(iii) a merger or consolidation effected to implement a recapitalization of Sempra Energy (or similar transaction) in which no Person is or becomes the Beneficial Owner, directly or indirectly, of securities of Sempra Energy (not including the securities beneficially owned by such Person any securities acquired directly from Sempra Energy or its Affiliates other than in connection with the acquisition by Sempra Energy or its Affiliates of a business) representing twenty percent (20%) or more of the combined voting power of Sempra Energy’s then outstanding securities.

(c) A “change in the ownership of a substantial portion of assets of Sempra Energy” shall not occur under clause (a)(iii) by reason of a sale or disposition by Sempra Energy of the assets of Sempra Energy to an entity, at least sixty percent (60%) of the combined voting power of the voting securities of which are owned by shareholders of Sempra Energy in substantially the same proportions as their ownership of Sempra Energy immediately prior to such sale.

(d) This definition of “Change in Control” shall be limited to the definition of a “change in control event” relating to Sempra Energy under Treasury Regulation Section 1.409A-3(i)(5). A “Change in Control” shall only occur if there is a “change in control event” relating to Sempra Energy under Treasury Regulation Section 1.409A-3(i)(5) with respect to the Executive.

“Change in Control Date” means the date on which a Change in Control occurs.

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

“Compensation Committee” means the compensation committee of the Board.

“Consulting Period” has the meaning assigned thereto in Section 14(e) hereof.

“Date of Termination” has the meaning assigned thereto in Section 3(b) hereof.

“Deferred Compensation Plan” has the meaning assigned thereto in Section 5(f) hereof.

“Disability” has the meaning set forth in the Company’s long-term disability plan or its successor; provided, however, that the Board may not terminate the Executive’s employment hereunder by reason of Disability unless (i) at the time of such termination there is no reasonable expectation that the Executive will return to work within the next ninety (90) day period and (ii) such termination is permitted by all applicable disability laws.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the applicable rulings and regulations thereunder.

“Excise Tax” has the meaning assigned thereto in Section 9(a) hereof.

“Good Reason” means:

(a) Prior to a Change in Control, the occurrence of any of the following without the prior written consent of the Executive, unless such act or failure to act is corrected by the Company prior to the Date of Termination specified in the Notice of Termination (as required under Section 3 hereof):

(i) the assignment to the Executive of any duties materially inconsistent with the range of duties and responsibilities appropriate to a senior Executive within the Company (such range determined by reference to past, current and reasonable practices within the Company);

(ii) a material reduction in the Executive’s overall standing and responsibilities within the Company, but not including (A) a mere change in title or (B) a transfer within the Company, which, in the case of both (A) and (B), does not adversely affect the Executive’s overall status within the Company;

(iii) a material reduction by the Company in the Executive’s aggregate annualized compensation and benefits opportunities, except for across-the-board reductions (or modifications of benefit plans) similarly affecting all similarly situated executives (both of the Company and of any Person then in control of the Company) of comparable rank with the Executive;

(iv) the failure by the Company to pay to the Executive any portion of the Executive’s current compensation and benefits or any portion of an installment of deferred compensation under any deferred compensation program of the Company within thirty (30) days of the date such compensation is due;

(v) any purported termination of the Executive’s employment that is not effected pursuant to a Notice of Termination satisfying the requirements of Section 3 hereof; for purposes of this Agreement, no such purported termination shall be effective;

(vi) the failure by Sempra Energy to perform its obligations under Section 16(c), (d) or (e) hereof;

(vii) the failure by the Company to provide the indemnification and D&O insurance protection Section 11 of this Agreement requires it to provide; or

(viii) the failure by Sempra Energy to comply with any material provision of this Agreement.

(b) From and after a Change in Control, the occurrence of any of the following without the prior written consent of the Executive, unless such act or failure to act is corrected by the Company prior to the Date of Termination specified in the Notice of Termination (as required under Section 3 hereof):

(i) an adverse change in the Executive’s title, authority, duties, responsibilities or reporting lines as in effect immediately prior to the Change in Control;

(ii) a reduction by the Company in the Executive’s aggregate annualized compensation opportunities, except for across-the-board reductions in base salaries, annual bonus opportunities or long-term incentive compensation opportunities of less than ten percent (10%) similarly affecting all similarly situated executives (both of the Company and of any Person then in control of the Company) of comparable rank with the Executive; or the failure by the Company to continue in effect any material benefit plan in which the Executive participates immediately prior to the Change in Control, unless an equitable arrangement (embodied in an ongoing substitute or alternative plan) has been made with respect to such plan, or the failure by the Company to continue the Executive's participation therein (or in such substitute or alternative plan) on a basis not materially less favorable, both in terms of the amount of benefits provided and the level of the Executive's participation relative to other participants, as existed at the time of the Change in Control;

(iii) the relocation of the Executive’s principal place of employment immediately prior to the Change in Control Date (the “Principal Location”) to a location which is both further away from the Executive’s residence and more than thirty (30) miles from such Principal Location, or the Company’s requiring the Executive to be based anywhere other than such Principal Location (or permitted relocation thereof), or a substantial increase in the Executive’s business travel obligations outside of the Southern California area as of the Effective Date other than any such increase that (A) arises in connection with extraordinary business activities of the Company of limited duration and (B) is understood not to be part of the Executive’s regular duties with the Company;

(vi) the failure by Sempra Energy to perform its obligations under Section 16(c), (d) or (e) hereof;

(vii) the failure by the Company to provide the indemnification and D&O insurance protection Section 11 of this Agreement requires it to provide; or

(viii) the failure by Sempra Energy to comply with any material provision of this Agreement.

Following a Change in Control, the Executive’s determination that an act or failure to act constitutes Good Reason shall be presumed to be valid unless such determination is deemed to be unreasonable by an arbitrator pursuant to the procedure described in Section 13 hereof. The Executive’s right to terminate the Executive’s employment for Good Reason shall not be affected by the Executive’s incapacity due to physical or mental illness. The Executive’s continued employment shall not constitute consent to, or a waiver of rights with respect to, any act or failure to act constituting Good Reason hereunder.

“Incentive Compensation Awards” means awards granted under Incentive Compensation Plans providing the Executive with the opportunity to earn, on a year-by-year basis, annual and long-term incentive compensation.

“Incentive Compensation Plans” means annual incentive compensation plans and long-term incentive compensation plans of the Company, which long-term incentive compensation plans may include plans offering stock options, restricted stock and other long-term incentive compensation.

“Involuntary Termination” means (a) the Executive’s Separation from Service by reason of a termination of employment by the Company other than for Cause, death, or Disability, or (b) the Executive’s Separation from Service by reason of resignation of employment with the Company for Good Reason.

“JAMS Rules” has the meaning assigned thereto in Section 13 hereof.

“Notice of Termination” has the meaning assigned thereto in Section 3(a) hereof.

“Payment” has the meaning assigned thereto in Section 9(a) hereof.

“Payment in Lieu of Notice” has the meaning assigned thereto in Section 3(b) hereof.

“Person” has the meaning set forth in section 3(a)(9) of the Exchange Act, as modified and used in sections 13(d) and 14(d) thereof, except that such term shall not include (i) the Company or any of its Affiliates, (ii) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (iii) an underwriter temporarily holding securities pursuant to an offering of such securities, (iv) a corporation owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of stock of the Company, or (v) a person or group as used in Rule 13d-1(b) promulgated under the Exchange Act.

“Post-Change in Control Accrued Obligations” has the meaning assigned thereto in Section 6(a) hereof.

“Post-Change in Control Severance Payment” has the meaning assigned thereto in Section 6 hereof.

“Pre-Change in Control Accrued Obligations” has the meaning assigned thereto in Section 5(a) hereof.

“Pre-Change in Control Severance Payment” has the meaning assigned thereto in Section 5 hereof.

“Principal Location” has the meaning assigned thereto in clause (b)(iii) of the definition of Good Reason, above.

“Proprietary Information” has the meaning assigned thereto in Section 14(a) hereof.

“Release” has the meaning assigned thereto in Section 14(d) hereof.

“Section 409A Payments” means any of the following: (a) the Payment in Lieu of Notice; (b) the Pre-Change in Control Severance Payment; (c) the Post-Change in Control Severance Payment; (d) the Additional Post-Change in Control Severance Payment; (e) the Consulting Payment; (f) the financial planning services and the related payments provided under Sections 5(e) and 6(e); and (g) the legal fees and expenses reimbursed under Section 15.

“Sempra Energy Control Group” means Sempra Energy and all persons with whom Sempra Energy would be considered a single employer under Section 414(b) or 414(c) of the Code, as determined from time to time.

“Separation from Service”, with respect to the Executive (or another Service Provider), means the Executive’s (or such Service Provider’s) (a) termination of employment or (b) other termination or reduction in services, provided that such termination or reduction in clause (a) or (b) constitutes a “separation from service,” as defined in Treasury Regulation Section 1.409A-1(h), with respect to the Service Recipient.

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

“Service Recipient,” with respect to the Executive, means Sempra Energy (if the Executive is employed by Sempra Energy), or the subsidiary of Sempra Energy employing the Executive, whichever is applicable, 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.

“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)), from the Service Recipient for such Testing Year. 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).

“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 Sempra Energy, in its discretion, in accordance with Treasury Regulation Section 1.409A-1(i)(4).

“Specified Employee Identification Date”, for purposes of Treasury Regulation Section 1.409A-1(i)(3), shall mean 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).

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

“Underpayment” has the meaning assigned thereto in Section 9(b) hereof.

For purposes of this Agreement, references to any “Treasury Regulation” shall mean such Treasury Regulation as in effect on the date hereof.

Section 2. Sarbanes-Oxley Act of 2002. Notwithstanding anything herein to the contrary, if the Company determines, in its good faith judgment, that any provision of this Agreement is likely to be interpreted as a personal loan prohibited by the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated thereunder (the “Act”), then such provision shall be modified as necessary or appropriate so as to not violate the Act; and if this cannot be accomplished, then the Company shall use its reasonable efforts to provide the Executive with similar, but lawful, substitute benefit(s) at a cost to the Company not to significantly exceed the amount the Company would have otherwise paid to provide such benefit(s) to the Executive. In addition, if the Executive is required to forfeit or to make any repayment of any compensation or benefit(s) to the Company under the Act or any other law, such forfeiture or repayment shall not constitute Good Reason.

Section 3. Notice and Date of Termination

(a) Any termination of the Executive’s employment by the Company or by the Executive shall be communicated by a written notice of termination to the other party (the “Notice of Termination”). Where applicable, the Notice of Termination shall indicate the specific termination provision in this Agreement relied upon and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Executive’s employment under the provision so indicated. Unless the Board determines otherwise, a Notice of Termination by the Executive alleging a termination for Good Reason must be made within 180 days of the act or failure to act that the Executive alleges to constitute Good Reason.

(b) The date of the Executive’s termination of employment with the Company (the “Date of Termination”) shall be determined as follows: (i) if the Executive has a Separation from Service by reason of the Company terminating his or her employment, either with or without Cause, the Date of Termination shall be the date specified in the Notice of Termination (which, in the case of a termination by the Company other than for Cause, shall not be less than two (2) weeks from the date such Notice of Termination is given unless the Company elects to pay the Executive, in addition to any other amounts payable hereunder, an amount (the “Payment in Lieu of Notice”) equal to two (2) weeks of the Executive’s Annual Base Salary in effect on the Date of Termination), and (ii) if the basis for the Executive’s Involuntary Termination is his resignation for Good Reason, the Date of Termination shall be determined by the Executive and specified in the Notice of Termination, but shall not in any event be less than fifteen (15) days nor more than sixty (60) days after the date such Notice of Termination is given. The Payment in Lieu of Notice shall be paid on such date as is determined by the Company within thirty (30) days after the date of the Executive’s Separation from Service; provided, however, that if the Executive is a Specified Employee on the date of his or her Separation from Service, such Payment in Lieu of Notice shall be paid as provided in Section 10 hereof.

Section 4. Termination from the Board. Upon the termination of the Executive’s employment for any reason, the Executive’s membership on the Board, the board of directors of any of the Company’s Affiliates, any committees of the Board and any committees of the board of directors of any of the Company’s Affiliates, if applicable, shall be automatically terminated.

Section 5. Severance Benefits upon Involuntary Termination Prior to Change in Control

. Except as provided in Section 6 and Section 19(i) hereof, in the event of the Involuntary Termination of the Executive prior to a Change in Control, the Company shall pay the Executive, in one lump sum cash payment, an amount (the “Pre-Change in Control Severance Payment”) equal to one-half (0.5) times the greater of: (X) 145% of the Executive’s Annual Base Salary as in effect on the Date of Termination, and (Y) the Executive’s Annual Base Salary as in effect on the Date of Termination, plus the Executive’s Average Annual Bonus. In addition to the Pre-Change in Control Severance Payment, the Executive shall be entitled to the following additional benefits specified in subsections (a) through (e). Except as provided in Section 5(f), the Pre-Change in Control Severance Payment and the payment under Section 5(a) shall be paid on such date as is determined by the Company within thirty (30) days after the date of the Involuntary Termination; provided, however, that, if the Executive is a Specified Employee on the date of the Executive’s Involuntary Termination, the Pre-Change in Control Severance Payment and the financial planning services and the related payments provided under Section 5(e) shall be paid as provided in Section 10 hereof.

(b) Equity Based Compensation. The Executive shall retain all rights to any equity-based compensation awards to the extent set forth in the applicable plan and/or award agreement.

(d) Outplacement Services. The Executive shall receive reasonable outplacement services, on an in-kind basis, suitable to his position and directly related to the Executive’s Involuntary Termination, for a period of twelve (12) months following the date of the Involuntary Termination, in an aggregate amount of cost to the Company not to exceed $50,000. Notwithstanding the foregoing, the Executive shall cease to receive outplacement services on the date the Executive accepts employment with a subsequent employer. Such outplacement services shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(b)(9)(v)(A).

(e) Financial Planning Services. The Executive shall receive financial planning services, on an in-kind basis, for a period of twelve (12) months following the Date of Termination. Such financial planning services shall include expert financial and legal resources to assist the Executive with financial planning needs and shall be limited to (i) current investment portfolio management, (ii) tax planning, (iii) tax return preparation, and (iv) estate planning advice and document preparation (including wills and trusts); provided, however, that the Company shall provide such financial planning services during any taxable year of the Executive only to the extent the cost to the Company for such taxable year does not exceed $25,000. The Company shall provide such financial planning services through a financial planner selected by the Company, and shall pay the fees for such financial planning services. The financial planning services provided during any taxable year of the Executive shall not affect the financial planning services provided in any other taxable year of the Executive. The Executive’s right to financial planning services shall not be subject to liquidation or exchange for any other benefit. Such financial planning services shall be provided in a manner that complies with Treasury Regulation Section 1.409A-3(i)(1)(iv).

(f) Deferral of Payments. The Executive shall have the right to elect to defer the Pre-Change in Control Severance Payment to be received by the Executive pursuant to this Section 5 under the terms and conditions of the Sempra Energy 2005 Deferred Compensation Plan (the “Deferred Compensation Plan”). Any such deferral election shall be made in accordance with Section 18(b) hereof.

Section 6. Severance Benefits upon Involuntary Termination in Connection with and after Change in Control

. Notwithstanding the provisions of Section 5 above, and except as provided in Section 19(i) hereof, in the event of the Involuntary Termination of the Executive on or within two (2) years following a Change in Control, in lieu of the payments described in Section 5 above, the Company shall pay the Executive, in one lump sum cash payment, an amount (the “Post-Change in Control Severance Payment”) equal to the greater of: (X) 145% of the Executive’s Annual Base Salary as in effect immediately prior to the Change in Control or the Date of Termination, whichever is greater, and (Y) the Executive’s Annual Base Salary as in effect immediately prior to the Change in Control or on the Date of Termination, whichever is greater, plus the Executive’s Average Annual Bonus; provided, however, that, in the event that the Involuntary Termination occurs prior to the fifth anniversary of the Effective Date, the Post-Change in Control Severance Payment shall be increased by twenty-five percent (25%). In addition to the Post-Change in Control Severance Payment, the Executive shall be entitled to the following additional benefits specified in subsections (a) through (e). Except as provided in Sections 6(f) and 6(g), the Post-Change in Control Severance Payment and the payments under Section 6(a) shall be paid on such date as is determined by the Company within thirty (30) days after the date of the Involuntary Termination; provided, however, that, if the Executive is a Specified Employee on the date of the Executive’s Involuntary Termination, the Post-Change in Control Severance Payment, the Additional Post-Change in Control Severance Payment under Section 6(a)(E), and the financial planning services and the related payments provided under Section 6(e) shall be paid as provided in Section 10 hereof.

(a) Accrued Obligations. The Company shall pay the Executive a lump sum amount in cash equal to the sum of (A) the Executive’s Annual Base Salary through the Date of Termination to the extent not theretofore paid, (B) an amount equal to any annual Incentive Compensation Awards earned with respect to fiscal years ended prior to the year that includes the Date of Termination to the extent not theretofore paid, (C) any accrued and unpaid vacation, if any, (D) reimbursement for unreimbursed business expenses, if any, properly incurred by the Executive in the performance of his duties in accordance with policies established from time to time by the Board, and (E) an amount (the “Additional Post-Change in Control Severance Payment”) equal to: (i) the greater of: (X) 45% of the Executive’s Annual Base Salary as in effect immediately prior to the Change in Control or on the Date of Termination, whichever is greater, or (Y) the Executive’s Average Annual Bonus, multiplied by (ii) a fraction, the numerator of which shall be the number of days from the beginning of such fiscal year to and including the Date of Termination and the denominator of which shall be 365, in the case of each amount described in clause (A), (B), (C) or (D) to the extent not theretofore paid. (The amounts specified in clauses (A), (B), (C), (D) and (E) shall be hereinafter referred to as the “Post-Change in Control Accrued Obligations”).

(b) Equity-Based Compensation. Notwithstanding the provisions of any applicable equity-compensation plan or award agreement to the contrary, all equity-based Incentive Compensation Awards (including, without limitation, stock options, stock appreciation rights, restricted stock awards, restricted stock units, performance share awards, awards covered under Section 162(m) of the Code, and dividend equivalents) held by the Executive shall immediately vest and become exercisable or payable, as the case may be, as of the Date of Termination, to be exercised or paid, as the case may be, in accordance with the terms of the applicable Incentive Compensation Plan and Incentive Compensation Award agreement, and any restrictions on any such Incentive Compensation Awards shall automatically lapse; provided, however, that any such stock option or stock appreciation rights awards granted on or after June 26, 1998 shall remain outstanding and exercisable until the earlier of (A) the later of eighteen (18) months following the Date of Termination or the period specified in the applicable Incentive Compensation Award agreements or (B) the expiration of the original term of such Incentive Compensation Award (or, if earlier, the tenth anniversary of the original date of grant) (it being understood that all Incentive Compensation Awards granted prior to or after June 26, 1998 shall remain outstanding and exercisable for a period that is no less than that provided for in the applicable agreement in effect as of the date of grant).

(c) Welfare Benefits. Subject to Section 12 below, for a period of six (6) months following the date of Involuntary Termination (and an additional twelve (12) months if the Executive provides consulting services under Section 14(e) hereof), the Executive and his dependents shall be provided with life, disability, accident and health insurance benefits substantially similar to those provided to the Executive and his dependents immediately prior to the date of Involuntary Termination or the Change in Control Date, whichever is more favorable to the Executive; provided, however, that such benefits shall be provided on substantially the same terms and conditions and at the same cost to the Executive as in effect immediately prior to the date of Involuntary Termination or the Change in Control Date, whichever is more favorable to the Executive. Such benefits shall be provided through insurance maintained by the Company under the Company benefit plans. Such benefits shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(a)(5).

(d) Outplacement Services. The Executive shall receive reasonable outplacement services, on an in-kind basis, suitable to his position and directly related to the Executive’s Involuntary Termination, for a period of eighteen (18) months following the date of Involuntary Termination (but in no event beyond the last day of the Executive’s second taxable year following the Executive’s taxable year in which the Involuntary Termination occurs), in the aggregate amount of cost to the Company not to exceed $50,000. Notwithstanding the foregoing, the Executive shall cease to receive outplacement services on the date the Executive accepts employment with a subsequent employer. Such outplacement services shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(b)(9)(v)(A).

(e) Financial Planning Services. The Executive shall receive financial planning services, on an in-kind basis, for a period of eighteen (18) months following the date of Involuntary Termination. Such financial planning services shall include expert financial and legal resources to assist the Executive with financial planning needs and shall be limited to (i) current investment portfolio management, (ii) tax planning, (iii) tax return preparation, and (iv) estate planning advice and document preparation (including wills and trusts); provided, however, that the Company shall provide such financial services during any taxable year of the Executive only to the extent the cost to the Company for such taxable year does not exceed $25,000. The Company shall provide such financial planning services through a financial planner selected by the Company, and shall pay the fees for such financial planning services. The financial planning services provided during any taxable year of the Executive shall not affect the financial planning services provided in any other taxable year of the Executive. The Executive’s right to financial planning services shall not be subject to liquidation or exchange for any other benefit. Such financial planning services shall be provided in a manner that complies with Section 1.409A-3(i)(1)(iv).

(f) Involuntary Termination in Connection with a Change in Control. Notwithstanding anything contained herein, in the event of an Involuntary Termination prior to a Change in Control, if the Involuntary Termination (1) was at the request of a third party who has taken steps reasonably calculated to effect such Change in Control or (2) otherwise arose in connection with or in anticipation of such Change in Control, then the Executive shall, in lieu of the payments described in Section 5 hereof, be entitled to the Post-Change in Control Severance Payment and the additional benefits described in this Section 6 as if such Involuntary Termination had occurred within two (2) years following the Change in Control. The amounts specified in Section 6 that are to be paid under this Section 6(f) shall be reduced by any amount previously paid under Section 5. The amounts to be paid under this Section 6(f) shall be paid within thirty (30) days after the Change in Control Date of such Change in Control.

(g) Deferral of Payments. The Executive shall have the right to elect to defer the Post-Change in Control Severance Payment to be received by the Executive pursuant to this Section 6 under the terms and conditions of the Deferred Compensation Plan. Any such deferral election shall be made in accordance with Section 18(b) hereof.

Section 7. Severance Benefits upon Termination by the Company for Cause or by the Executive Other than for Good Reason. If the Executive’s employment shall be terminated for Cause, or if the Executive terminates employment other than for Good Reason, the Company shall have no further obligations to the Executive under this Agreement other than the Pre-Change in Control Accrued Obligations and any amounts or benefits described in Section 11 hereof.

Section 8. Severance Benefits upon Termination due to Death or Disability. If the Executive has a Separation from Service by reason of death or Disability, the Company shall pay the Executive or his estate, as the case may be, the Post-Change in Control Accrued Obligations (without regard to whether a Change in Control has occurred) and any amounts or benefits described in Section 11 hereof. Such payments shall be in addition to those rights and benefits to which the Executive or his estate may be entitled under the relevant Company plans or programs. Such payments shall be paid on such date as determined by the Company within thirty (30) days after the date of the Separation from Service; provided, however, that if the Executive is a Specified Employee on the date of the Executive’s Separation from Service by reason of Disability, the Additional Post-Change in Control Severance Payment under Section 6(a)(E) shall be paid as provided in Section 10 hereof.

Section 9. Limitation on Payments by the Company.

(a) Anything in this Agreement to the contrary notwithstanding and except as set forth in this Section 9 below, in the event it shall be determined that any payment or distribution in the nature of compensation (within the meaning of Section 280G(b)(2) of the Code) to or for the benefit of the Executive, whether paid or payable pursuant to this Agreement or otherwise (the “Payment”) would be subject (in whole or in part) to the excise tax imposed by Section 4999 of the Code, (the “Excise Tax”), then, subject to subsection (b), the Pre-Change in Control Severance Benefit or the Post-Change in Control Severance Payment (whichever is applicable) payable under this Agreement shall be reduced under this subsection (a) to the amount equal to the Reduced Payment. For such Payment payable under this Agreement, the “Reduced Payment” shall be the amount equal to the greatest portion of the Payment (which may be zero) that, if paid, would result in no portion of any Payment being subject to the Excise Tax.

(b) The Pre-Change in Control Severance Benefit or the Post-Change in Control Severance Payment (whichever is applicable) payable under this Agreement shall not be reduced under subsection (a) if:

(i) such reduction in such Payment is not sufficient to cause no portion of any Payment to be subject to the Excise Tax, or

(ii) the Net After-Tax Unreduced Payments (as defined below) would equal or exceed one hundred and five percent (105%) of the Net After-Tax Reduced Payments (as defined below).

For purposes of determining the amount of any Reduced Payment under subsection (a), and the Net-After Tax Reduced Payments and the Net After-Tax Unreduced Payments, the Executive shall be considered to pay federal, state and local income and employment taxes at the Executive’s applicable marginal rates taking into consideration any reduction in federal income taxes which could be obtained from the deduction of state and local income taxes, and any reduction or disallowance of itemized deductions and personal exemptions under applicable tax law). The applicable federal, state and local income and employment taxes and the Excise Tax (to the extent applicable) are collectively referred to as the “Taxes”.

(i) “Net After-Tax Reduced Payments” shall mean the total amount of all Payments that the Executive would retain, on a Net After-Tax Basis, in the event that the Payments payable under this Agreement are reduced pursuant to subsection (a).

(ii) “Net After-Tax Unreduced Payments” shall mean the total amount of all Payments that the Executive would retain, on a Net After-Tax Basis, in the event that the Payments payable under this Agreement are not reduced pursuant to subsection (a).

(iii) “Net After-Tax Basis” shall mean, with respect to the Payments, either with or without reduction under subsection (a) (as applicable), the amount that would be retained by the Executive from such Payments after the payment of all Taxes.

(d) All determinations required to be made under this Section 9 and the assumptions to be utilized in arriving at such determinations, shall be made by a nationally recognized accounting firm as may be agreed by the Company and the Executive (the “Accounting Firm”); provided, that the Accounting Firm’s determination shall be made based upon “substantial authority” within the meaning of Section 6662 of the Code. The Accounting Firm shall provide detailed supporting calculations to both the Company and the Executive within fifteen (15) business days of the receipt of notice from the Executive that there has been a Payment or such earlier time as is requested by the Company. All fees and expenses of the Accounting Firm shall be borne solely by the Company. Any determination by the Accounting Firm shall be binding upon the Company and the Executive. For purposes of determining whether and the extent to which the Payments will be subject to the Excise Tax, (i) no portion of the Payments the receipt or enjoyment of which the Executive shall have waived at such time and in such manner as not to constitute a “payment” within the meaning of Section 280G(b) of the Code shall be taken into account, (ii) no portion of the Payments shall be taken into account which, in the written opinion of the Accounting Firm, does not constitute a “parachute payment” within the meaning of Section 280G(b)(2) of the Code (including by reason of Section 280G(b)(4)(A) of the Code) and, in calculating the Excise Tax, no portion of such Payments shall be taken into account which, in the opinion of the Accounting Firm, constitutes reasonable compensation for services actually rendered, within the meaning of Section 280G(b)(4)(B) of the Code, in excess of the base amount (as defined in Section 280G(b)(3) of the Code) allocable to such reasonable compensation, and (iii) the value of any non-cash benefit or any deferred payment or benefit included in the Payments shall be determined by the Accounting Firm in accordance with the principles of Sections 280G(d)(3) and (4) of the Code.

Section 10. Delayed Distribution under Section 409A of the Code. If the Executive is a Specified Employee on the date of the Executive’s Involuntary Termination (or on the date of the Executive’s Separation from Service by reason of Disability), the Section 409A Payments, and any other payments or benefits under this Agreement subject to Section 409A of the Code, shall be delayed in order to avoid a prohibited distribution under Section 409A(a)(2)(B)(i) of the Code, and such payments or benefits shall be paid or distributed to the Executive during the thirty (30) day period commencing on the earlier of (a) the expiration of the six-month period measured from the date of the Executive’s Separation from Service or (b) the date of the Executive’s death. Upon the expiration of the applicable six-month period under Section 409A(a)(2)(B)(i) of the Code, all payments deferred pursuant to this Section 10 (excluding in-kind benefits) shall be paid in a lump sum payment to the Executive, plus interest thereon from the date of the Executive’s Involuntary Termination through the payment date at an annual rate equal to Moody’s Rate. The “Moody’s Rate” shall mean the average of the daily Moody’s Corporate Bond Yield Average – Monthly Average Corporates as published by Moody’s Investors Service, Inc. (or any successor) for the month next preceding the Date of Termination. Any remaining payments due under the Agreement shall be paid as otherwise provided herein.

Section 11. Nonexclusivity of Rights. Nothing in this Agreement shall prevent or limit the Executive’s continuing or future participation in any benefit, plan, program, policy or practice provided by the Company and for which the Executive may qualify (except with respect to any benefit to which the Executive has waived his rights in writing), including, without limitation, any and all indemnification arrangements in favor of the Executive (whether under agreements or under the Company’s charter documents or otherwise), and insurance policies covering the Executive, nor shall anything herein limit or otherwise affect such rights as the Executive may have under any other contract or agreement entered into after the Effective Date with the Company. Amounts which are vested benefits or which the Executive is otherwise entitled to receive under any benefit, plan, policy, practice or program of, or any contract or agreement entered into with, the Company shall be payable in accordance with such benefit, plan, policy, practice or program or contract or agreement except as explicitly modified by this Agreement. At all times during the Executive’s employment with the Company and thereafter, the Company shall provide (to the extent permissible under applicable law) the Executive with indemnification and D&O insurance insuring the Executive against insurable events which occur or have occurred while the Executive was a director or the Executive officer of the Company, on terms and conditions that are at least as generous as that then provided to any other current or former director or the Executive officer of the Company or any Affiliate. Such indemnification and D&O insurance shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(b)(10).

Section 12. Full Settlement; Mitigation. The Company’s obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action which the Company may have against the Executive or others, provided that nothing herein shall preclude the Company from separately pursuing recovery from the Executive based on any such claim. In no event shall the Executive be obligated to seek other employment or take any other action by way of mitigation of the amounts (including amounts for damages for breach) payable to the Executive under any of the provisions of this Agreement, and such amounts shall not be reduced whether or not the Executive obtains other employment.

Section 13. Dispute Resolution.

Any disagreement, dispute, controversy or claim arising out of or relating to this Agreement or the interpretation of this Agreement or any arrangements relating to this Agreement or contemplated in this Agreement or the breach, termination or invalidity thereof shall be settled by final and binding arbitration administered by JAMS in San Diego, California in accordance with the then existing JAMS arbitration rules applicable to employment disputes (the “JAMS Rules”); provided that, notwithstanding any provision in such rules to the contrary, in all cases the parties shall be entitled to reasonable discovery. In the event of such an arbitration proceeding, the Executive and the Company shall select a mutually acceptable neutral arbitrator from among the JAMS panel of arbitrators. In the event the Executive and the Company cannot agree on an arbitrator, the arbitrator shall be selected in accordance with the then existing JAMS Rules. Neither the Executive nor the Company nor the arbitrator shall disclose the existence, content or results of any arbitration hereunder without the prior written consent of all parties, except to the extent necessary to enforce any arbitration award in a court of competent jurisdiction. Except as provided herein, the Federal Arbitration Act shall govern the interpretation of, enforcement of and all proceedings under this agreement to arbitrate. The arbitrator shall apply the substantive law (and the law of remedies, if applicable) of the state of California, or federal law, or both, as applicable, and the arbitrator is without jurisdiction to apply any different substantive law. The arbitrator shall have the authority to entertain a motion to dismiss and/or a motion for summary judgment by any party and shall apply the standards governing such motions under the Federal Rules of Civil Procedure. The arbitrator shall render an award and a written, reasoned opinion in support thereof. Judgment upon the award may be entered in any court having jurisdiction thereof. The Executive shall not be required to pay any arbitration fee or cost that is unique to arbitration or greater than any amount he would be required to pay to pursue his claims in a court of competent jurisdiction.

Section 14. Executive’s Covenants.

(a) Confidentiality. The Executive acknowledges that in the course of his employment with the Company, he has acquired non-public privileged or confidential information and trade secrets concerning the operations, future plans and methods of doing business (“Proprietary Information”) of the Company and its Affiliates; and the Executive agrees that it would be extremely damaging to the Company and its Affiliates if such Proprietary Information were disclosed to a competitor of the Company and its Affiliates or to any other person or corporation. The Executive understands and agrees that all Proprietary Information has been divulged to the Executive in confidence and further understands and agrees to keep all Proprietary Information secret and confidential (except for such information which is or becomes publicly available other than as a result of a breach by the Executive of this provision or information the Executive is required by any governmental, administrative or court order to disclose) without limitation in time. In view of the nature of the Executive’s employment and the Proprietary Information the Executive has acquired during the course of such employment, the Executive likewise agrees that the Company and its Affiliates would be irreparably harmed by any disclosure of Proprietary Information in violation of the terms of this paragraph and that the Company and its Affiliates shall therefore be entitled to preliminary and/or permanent injunctive relief prohibiting the Executive from engaging in any activity or threatened activity in violation of the terms of this paragraph and to any other relief available to them. Inquiries regarding whether specific information constitutes Proprietary Information shall be directed to the Company’s Senior Vice President, Public Policy (or, if such position is vacant, the Company’s then Chief Executive Officer); provided, that the Company shall not unreasonably classify information as Proprietary Information.

(b) Non-Solicitation of Employees. The Executive recognizes that he possesses and will possess confidential information about other employees of the Company and its Affiliates relating to their education, experience, skills, abilities, compensation and benefits, and inter-personal relationships with customers of the Company and its Affiliates. The Executive recognizes that the information he possesses and will possess about these other employees is not generally known, is of substantial value to the Company and its Affiliates in developing their business and in securing and retaining customers, and has been and will be acquired by him because of his business position with the Company and its Affiliates. The Executive agrees that at all times during the Executive’s employment with the Company and for a period of one (1) year thereafter, he will not, directly or indirectly, solicit or recruit any employee of the Company or its Affiliates for the purpose of being employed by him or by any competitor of the Company or its Affiliates on whose behalf he is acting as an agent, representative or employee and that he will not convey any such confidential information or trade secrets about other employees of the Company and its Affiliates to any other person; provided, however, that it shall not constitute a solicitation or recruitment of employment in violation of this paragraph to discuss employment opportunities with any employee of the Company or its Affiliates who has either first contacted the Executive or regarding whose employment the Executive has discussed with and received the written approval of the Company’s Vice President, Human Resources (or, if such position is vacant, the Company’s then Chief Executive Officer), prior to making such solicitation or recruitment. In view of the nature of the Executive’s employment with the Company, the Executive likewise agrees that the Company and its Affiliates would be irreparably harmed by any solicitation or recruitment in violation of the terms of this paragraph and that the Company and its Affiliates shall therefore be entitled to preliminary and/or permanent injunctive relief prohibiting the Executive from engaging in any activity or threatened activity in violation of the terms of this paragraph and to any other relief available to them.

(c) Survival of Provisions. The obligations contained in Section 14(a) and Section 14(b) above shall survive the termination of the Executive’s employment within the Company and shall be fully enforceable thereafter. If it is determined by a court of competent jurisdiction in any state that any restriction in Section 14(a) or Section 14(b) above is excessive in duration or scope or is unreasonable or unenforceable under the laws of that state, it is the intention of the parties that such restriction may be modified or amended by the court to render it enforceable to the maximum extent permitted by the law of that state.

(d) Release; Lump Sum Payment. In the event of the Executive’s Involuntary Termination, if the Executive (i) agrees to the covenants described in Section 14(a) and Section 14(b) above, (ii) executes a release (the “Release”) of all claims substantially in the form attached hereto as Exhibit A within fifty (50) days after the date of Involuntary Termination and does not revoke such Release in accordance with the terms thereof, and (iii) agrees to provide the consulting services described in Section 14(e) below, then in consideration for such covenants, the Company shall pay the Executive, in one cash lump sum, an amount (the “Consulting Payment”) in cash equal to one-half (0.5) times the greater of: (X) 145% of the Executive’s Annual Base Salary as in effect on the Date of Termination, and (Y) the Executive’s Annual Base Salary as in effect on the Date of Termination, plus the Executive’s Average Annual Bonus. Except as provided in this subsection, the Consulting Payment shall be paid on such date as is determined by the Company within the ten (10) day period commencing on the 60th day after the date of the Executive’s Involuntary Termination; provided, however, that if the Executive is a Specified Employee on the date of the Executive’s Involuntary Termination, the Consulting Payment shall be paid as provided in Section 10 hereof. The Executive shall have the right to elect to defer the Consulting Payment under the terms and conditions of the Company’s Deferred Compensation Plan. Any such deferral election shall be made in accordance with Section 18(b) hereof.

(e) Consulting. If the Executive agrees to the covenants described in Section 14(d) above, then the Executive shall have the obligation to provide consulting services to the Company as an independent contractor, commencing on the Date of Termination and ending on the first anniversary of the Date of Termination (the “Consulting Period”). The Executive shall hold himself available at reasonable times and on reasonable notice to render such consulting services as may be so assigned to him by the Board or the Company’s then Chief Executive Officer; provided, however, that unless the parties otherwise agree, the consulting services rendered by the Executive during the Consulting Period shall not exceed twenty (20) hours each month; and, provided, further, that the consulting services rendered by the Executive during the Consulting Period shall in no event exceed twenty percent (20%) of the average level of services performed by the Executive for the Company over the thirty-six (36) month period immediately preceding the Executive’s Separation from Service (or the full period of services to the Company, if the Executive has been providing services to the Company for less than thirty-six (36) months). The Company agrees to use its best efforts during the Consulting Period to secure the benefit of the Executive’s consulting services so as to minimize the interference with the Executive’s other activities, including requiring the performance of consulting services at the Company’s offices only when such services may not be reasonably performed off-site by the Executive.

Section 15. Legal Fees.

(a) Reimbursement of Legal Fees. Subject to subsection (b), in the event of the Executive’s Separation from Service either (1) prior to a Change in Control, or (2) on or within two (2) years following a Change in Control, the Company shall reimburse the Executive for all legal fees and expenses (including but not limited to fees and expenses in connection with any arbitration) incurred by the Executive in disputing any issue arising under this Agreement relating to the Executive’s Separation from Service or in seeking to obtain or enforce any benefit or right provided by this Agreement.

(b) Requirements for Reimbursement. The Company shall reimburse the Executive’s legal fees and expenses pursuant to subsection (a) above only to the extent the arbitrator or court determines the following: (i) the Executive disputed such issue, or sought to obtain or enforce such benefit or right, in good faith, (ii) the Executive had a reasonable basis for such claim, and (iii) in the case of subsection (a)(1) above, the Executive is the prevailing party. In addition, the Company shall reimburse such legal fees and expenses, only if such legal fees and expenses are incurred during the twenty (20) year period beginning on the date of the Executive’s Separation from Service. The legal fees and expenses paid to the Executive for any taxable year of the Executive shall not affect the legal fees and expenses paid to the Executive for any other taxable year of the Executive. The legal fees and expenses shall be paid to the Executive on or before the last day of the Executive’s taxable year following the taxable year in which the fees or expenses are incurred. The Executive’s right to reimbursement of legal fees and expenses shall not be subject to liquidation or exchange for any other benefit. Such right to reimbursement of legal fees and expenses shall be provided in a manner that complies with Treasury Regulation Section 1.409A-3(i)(1)(iv). If the Executive is a Specified Employee on the date of the Executive’s Separation from Service, such right to reimbursement of legal fees and expenses shall be paid as provided in Section 10 hereof.

Section 16. Successors.

(a) Assignment by the Executive. This Agreement is personal to the Executive and without the prior written consent of Sempra Energy shall not be assignable by the Executive otherwise than by will or the laws of descent and distribution. This Agreement shall inure to the benefit of and be enforceable by the Executive’s legal representatives.

(b) Successors and Assigns of Sempra Energy. This Agreement shall inure to the benefit of and be binding upon Sempra Energy, its successors and assigns. Sempra Energy may not assign this Agreement to any person or entity (except for a successor described in Section 16(c), (d) or (e) below) without the Executive’s written consent.

(c) Assumption. Sempra Energy shall require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of Sempra Energy to assume expressly and agree to perform the obligations and satisfy and discharge the liabilities of this Agreement in the same manner and to the same extent that Sempra Energy would have been required to perform the obligations and satisfy and discharge the liabilities under this Agreement if no such succession had taken place, and Sempra Energy shall have no further obligations and liabilities under this Agreement. Upon such assumption, references to Sempra Energy in this Agreement shall be replaced with references to such successor.

(d) Sale of Subsidiary. In the event that (i) the Executive is employed by a direct or indirect subsidiary of Sempra Energy that is a member of the Sempra Energy Control Group, (ii) Sempra Energy, directly or indirectly through one or more intermediaries, sells or otherwise disposes of such subsidiary, and (iii) such subsidiary ceases to be a member of the Sempra Energy Control Group, then if, on the date such subsidiary ceases to be a member of the Sempra Energy Control Group, the Executive continues in employment with such subsidiary and the Executive does not have a Separation from Service, Sempra Energy shall require such subsidiary or any successor (whether direct or indirect, by purchase merger, consolidation or otherwise) to such subsidiary, or the parent thereof, to assume expressly and agree to perform the obligations and satisfy and discharge the liabilities under this Agreement in the same manner and to the same extent that Sempra Energy would have been required to perform the obligations and satisfy and discharge the liabilities under this Agreement, if such subsidiary had not ceased to be part of the Sempra Energy Control Group, and, upon such assumption, Sempra Energy shall have no further obligations and liabilities under the Agreement. Upon such assumption, (i) references to Sempra Energy in this Agreement shall be replaced with references to such subsidiary, or such successor or parent thereof, assuming this Agreement, and (ii) subsection (b) of the definition of “Cause” and subsection (b) of the definition of “Good Reason” shall apply thereafter, as if a Change in Control had occurred on the date of such cessation.

(e) Sale of Assets of Subsidiary. In the event that (i) the Executive is employed by a direct or indirect subsidiary of Sempra Energy, and (ii) such subsidiary sells or otherwise disposes of substantial assets of such subsidiary to an unrelated service recipient, as determined under Treasury Regulation Section 1.409A-1(f)(2)(ii) (the “Asset Purchaser”), in a transaction described in Treasury Regulation Section 1.409A-1(h)(4) (an “Asset Sale”), then if, on the date of such Asset Sale, the Executive becomes employed by the Asset Purchaser, Sempra Energy and the Asset Purchaser shall specify, in accordance with Treasury Regulation Section 1.409A-1(h)(4), that the Executive shall not be treated as having a Separation from Service, and Sempra Energy shall require such Asset Purchaser, or the parent thereof, to assume expressly and agree to perform the obligations and satisfy and discharge the liabilities under this Agreement in the same manner and to the same extent that Sempra Energy would have been required to perform the obligations and satisfy and discharge the liabilities under this Agreement, if the Asset Sale had not taken place, and, upon such assumption, Sempra Energy shall have no further obligations and liabilities under the Agreement. Upon such assumption, (i) references to Sempra Energy in this Agreement shall be replaced with references to the Asset Purchaser or the parent thereof, as applicable, and (ii) subsection (b) of the definition of “Cause” and subsection (b) of the definition of “Good Reason” shall apply thereafter, as if a Change in Control had occurred on the date of the Asset Sale.

Section 17. Administration Prior to Change in Control. Prior to a Change in Control, the Compensation Committee shall have full and complete authority to construe and interpret the provisions of this Agreement, to determine an individual’s entitlement to benefits under this Agreement, to make in its sole and absolute discretion all determinations contemplated under this Agreement, to investigate and make factual determinations necessary or advisable to administer or implement this Agreement, and to adopt such rules and procedures as it deems necessary or advisable for the administration or implementation of this Agreement. All determinations made under this Agreement by the Compensation Committee shall be final and binding on all interested persons. Prior to a Change in Control, the Compensation Committee may delegate responsibilities for the operation and administration of this Agreement to one or more officers or employees of the Company. The provisions of this Section 17 shall terminate and be of no further force and effect upon the occurrence of a Change in Control.

Section 18. Section 409A of the Code.

(a) Compliance with and Exemption from Section 409A of the Code. Certain payments and benefits payable under this Agreement (including, without limitation, the Section 409A Payments) are intended to comply with the requirements of Section 409A of the Code. Certain payments and benefits payable under this Agreement are intended to be exempt from the requirements of Section 409A of the Code. This Agreement shall be interpreted in accordance with the applicable requirements of, and exemptions from, Section 409A of the Code and the Treasury Regulations thereunder. To the extent the payments and benefits under this Agreement are subject to Section 409A of the Code, this Agreement 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 Agreement, with respect to an election or amendment to change a time or form of payment under this Agreement made on or after January 1, 2008 and on or before December 31, 2008, the election or amendment shall apply only with respect to payments that would not otherwise be payable in 2008, and shall not cause payments to be made in 2008 that would not otherwise be payable in 2008. If the Company and the Executive determine that any compensation, benefits or other payments that are payable under this Agreement and intended to comply with Sections 409A(a)(2), (3) and (4) of the Code do not comply with Section 409A of the Code, the Treasury Regulations thereunder and other applicable authority issued by the Internal Revenue Service, to the extent permitted under Section 409A of the Code, the Treasury Regulations thereunder and any applicable authority issued by the Internal Revenue Service, the Company and the Executive agree to amend this Agreement, or take such other actions as the Company and the Executive deem reasonably necessary or appropriate, to cause such compensation, benefits and other payments to comply with the requirements of Section 409A of the Code, the Treasury Regulations thereunder and other applicable authority issued by the Internal Revenue Service, while providing compensation, benefits and other payments that are, in the aggregate, no less favorable than the compensation, benefits and other payments provided under this Agreement. In the case of any compensation, benefits or other payments that are payable under this Agreement and intended to comply with Sections 409A(a)(2), (3) and (4) of the Code, if any provision of the Agreement would cause such compensation, benefits or other payments to fail to so comply, such provision shall not be effective and shall be null and void with respect to such compensation, benefits or other payments to the extent such provision would cause a failure to comply, and such provision shall otherwise remain in full force and effect.

(b) Deferral Elections. As provided in Sections 5(f), 6(g) and 14(d), the Executive may elect to defer the Pre-Change in Control Severance Payment, the Post-Change in Control Severance Payment and the Consulting Payment as follows. The Executive’s deferral election shall satisfy the requirements of Treasury Regulation Section 1.409A-2(b) and the terms and conditions of the Deferred Compensation Plan. Such deferral election shall designate the whole percentage (up to a maximum of 100%) of the Pre-Change in Control Severance Payment, the Post-Change in Control Severance Payment and the Consulting Payment to be deferred, shall be irrevocable when made, and shall not take effect until at least twelve (12) months after the date on which the election is made. Such deferral election shall provide that the amount deferred shall be deferred for a period of not less than five (5) years from the date the payment of the amount deferred would otherwise have been made, in accordance with Treasury Regulation Section 1.409A-2(b)(1)(ii).

Section 19. Miscellaneous.

(a) Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of California, without reference to its principles of conflict of laws. The captions of this Agreement are not part of the provisions hereof and shall have no force or effect. This Agreement may not be amended, modified, repealed, waived, extended or discharged except by an agreement in writing signed by the party against whom enforcement of such amendment, modification, repeal, waiver, extension or discharge is sought. No person, other than pursuant to a resolution of the Board or a committee thereof, shall have authority on behalf of the Company to agree to amend, modify, repeal, waive, extend or discharge any provision of this Agreement or anything in reference thereto.

(b) Notices. All notices and other communications hereunder shall be in writing and shall be given by hand delivery to the other party or by registered or certified mail, return receipt requested, postage prepaid, addressed, in either case, to the Company’s headquarters or to such other address as either party shall have furnished to the other in writing in accordance herewith. Notices and communications shall be effective when actually received by the addressee.

(c) Severability. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement.

(d) Taxes. The Company may withhold from any amounts payable under this Agreement such federal, state or local taxes as shall be required to be withheld pursuant to any applicable law or regulation.

(e) No Waiver. The Executive’s or the Company’s failure to insist upon strict compliance with any provision hereof or any other provision of this Agreement or the failure to assert any right the Executive or the Company may have hereunder, including, without limitation, the right of the Executive to terminate employment for Good Reason pursuant to Section 1 hereof, or the right of the Company to terminate the Executive’s employment for Cause pursuant to Section 1 hereof shall not be deemed to be a waiver of such provision or right or any other provision or right of this Agreement.

(f) Entire Agreement; Exclusive Benefit; Supersession of Prior Agreement. This instrument contains the entire agreement of the Executive, the Company or any predecessor or subsidiary thereof with respect to any severance or termination pay. The Pre-Change in Control Severance Payment, the Post-Change in Control Severance Payment and all other benefits provided hereunder shall be in lieu of any other severance payments to which the Executive is entitled under any other severance plan or program or arrangement sponsored by the Company, as well as pursuant to any individual employment or severance agreement that was entered into by the Executive and the Company, and, upon the Effective Date of this Agreement, all such plans, programs, arrangements and agreements are hereby automatically superseded and terminated.

(g) No Right of Employment. Nothing in this Agreement shall be construed as giving the Executive any right to be retained in the employ of the Company or shall interfere in any way with the right of the Company to terminate the Executive’s employment at any time, with or without Cause.

(h) Unfunded Obligation. The obligations under this Agreement shall be unfunded. Benefits payable under this Agreement shall be paid from the general assets of the Company. The Company shall have no obligation to establish any fund or to set aside any assets to provide benefits under this Agreement.

(i) Termination upon Sale of Assets of Subsidiary. Notwithstanding anything contained herein, this Agreement shall automatically terminate and be of no further force and effect and no benefits shall be payable hereunder in the event that (i) the Executive is employed by a direct or indirect subsidiary of Sempra Energy, and (ii) an Asset Sale (as defined in Section 16(e)) occurs (other than such a sale or disposition which is part of a transaction or series of transactions which would result in a Change in Control), and (iii) as a result of such Asset Sale, the Executive is offered employment by the Asset Purchaser in an executive position with reasonably comparable status, compensation, benefits and severance agreement (including the assumption of this Agreement in accordance with Section 16(e)) and which is consistent with the Executive’s experience and education, but the Executive declines to accept such offer and the Executive fails to become employed by the Asset Purchaser on the date of the Asset Sale.

(j) Term. The term of this Agreement shall commence on the Effective Date and shall continue until the third (3rd) anniversary of the Effective Date; provided, however, that commencing on the second (2nd) anniversary of the Effective Date (and each anniversary of the Effective Date thereafter), the term of this Agreement shall automatically be extended for one (1) additional year, unless at least ninety (90) days prior to such date, the Company or the Executive shall give written notice to the other party that it or he, as the case may be, does not wish to so extend this Agreement. Notwithstanding the foregoing, if the Company gives such written notice to the Executive less than two (2) years after a Change in Control, the term of this Agreement shall be automatically extended until the later of (A) the date that is one (1) year after the anniversary of the Effective Date that follows such written notice or (B) the second (2nd) anniversary of the Change in Control Date.

(k) Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument.

IN WITNESS WHEREOF, the Executive and, pursuant to due authorization from its Board of Directors, the Company have caused this Agreement to be executed as of the day and year first above written.

SEMPRA ENERGY

G. Joyce Rowland

Senior Vice President, Human Resources, Diversity and Inclusion

_____________________________________

Date

EXECUTIVE

Bruce Folkmann

Vice President & Controller, USG&P

_____________________________________

Date

EXHIBIT A

GENERAL RELEASE

This GENERAL RELEASE (the “Agreement”), dated ___________, is made by and between ______________________________, a California corporation (the “Company”) and ___________________________ (“you” or “your”).

WHEREAS, you and the Company have previously entered into that certain Severance Pay Agreement dated ____________, 20__ (the “Severance Pay Agreement”); and

WHEREAS, Section 14(d) of the Severance Pay Agreement provides for the payment of a benefit to you by the Company in consideration for certain covenants, including your execution and non-revocation of a general release of claims by you against the Company and its subsidiaries and affiliates.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, you and the Company hereby agree as follows:

ONE: Your signing of this Agreement confirms that your employment with the Company shall terminate at the close of business on ____________, or earlier upon our mutual agreement.

TWO: As a material inducement for the payment of the benefit under Section 14(d) of the Severance Pay Agreement, and except as otherwise provided in this Agreement, you and the Company hereby irrevocably and unconditionally release, acquit and forever discharge the other from any and all Claims either may have against the other. For purposes of this Agreement and the preceding sentence, the words “Releasee” or “Releasees” and “Claim” or “Claims” shall have the meanings set forth below:

(a) The words “Releasee” or “Releasees” shall refer to you and to the Company and each of the Company’s owners, stockholders, predecessors, successors, assigns, agents, directors, officers, employees, representatives, attorneys, advisors, parent companies, divisions, subsidiaries, affiliates (and agents, directors, officers, employees, representatives, attorneys and advisors of such parent companies, divisions, subsidiaries and affiliates) and all persons acting by, through, under or in concert with any of them.

(b) The words “Claim” or “Claims” shall refer to any charges, complaints, claims, liabilities, obligations, promises, agreements, controversies, damages, actions, causes of action, suits, rights, demands, costs, losses, debts and expenses (including attorneys’ fees and costs actually incurred) of any nature whatsoever, known or unknown, suspected or unsuspected, which you or the Company now, in the past or, except as limited by law or regulation such as the Age Discrimination in Employment Act (ADEA), in the future may have, own or hold against any of the Releasees; provided, however, that the word “Claim” or “Claims” shall not refer to any charges, complaints, claims, liabilities, obligations, promises, agreements, controversies, damages, actions, causes of action, suits, rights, demands, costs, losses, debts and expenses (including attorneys’ fees and costs actually incurred) arising under [identify severance, employee benefits, stock option, indemnification and D&O and other agreements containing duties, rights obligations etc. of either party that are to remain operative]. Claims released pursuant to this Agreement by you and the Company include, but are not limited to, rights arising out of alleged violations of any contracts, express or implied, any tort, any claim that you failed to perform or negligently performed or breached your duties during employment at the Company, any legal restrictions on the Company’s right to terminate employees or any federal, state or other governmental statute, regulation, or ordinance, including, without limitation: (1) Title VII of the Civil Rights Act of 1964 (race, color, religion, sex and national origin discrimination); (2) 42 U.S.C. § 1981 (discrimination); (3) 29 U.S.C. §§ 621–634 (age discrimination); (4) 29 U.S.C. § 206(d)(l) (equal pay); (5) 42 U.S.C. §§ 12101, et seq. (disability); (6) the California Constitution, Article I, Section 8 (discrimination); (7) the California Fair Employment and Housing Act (discrimination, including race, color, national origin, ancestry, physical handicap, medical condition, marital status, religion, sex or age); (8) California Labor Code Section 1102.1 (sexual orientation discrimination); (9) the Executive Order 11246 (race, color, religion, sex and national origin discrimination); (10) the Executive Order 11141 (age discrimination); (11) §§ 503 and 504 of the Rehabilitation Act of 1973 (handicap discrimination); (12) The Worker Adjustment and Retraining Act (WARN Act); (13) the California Labor Code (wages, hours, working conditions, benefits and other matters); (14) the Fair Labor Standards Act (wages, hours, working conditions and other matters); the Federal Employee Polygraph Protection Act (prohibits employer from requiring employee to take polygraph test as condition of employment); and (15) any federal, state or other governmental statute, regulation or ordinance which is similar to any of the statutes described in clauses (1) through (14).

THREE: You and the Company expressly waive and relinquish all rights and benefits afforded by any statute (including but not limited to Section 1542 of the Civil Code of the State of California) which limits the effect of a release with respect to unknown claims. You and the Company do so understanding and acknowledging the significance of the release of unknown claims and the waiver of statutory protection against a release of unknown claims (including but not limited to Section 1542). Section 1542 of the Civil Code of the State of California states as follows:

“A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT KNOW OR SUSPECT TO EXIST IN HIS FAVOR AT THE TIME OF EXECUTING THE RELEASE, WHICH IF KNOWN BY HIM MUST HAVE MATERIALLY AFFECTED HIS SETTLEMENT WITH THE DEBTOR.”

Thus, notwithstanding the provisions of Section 1542 or of any similar statute, and for the purpose of implementing a full and complete release and discharge of the Releasees, you and the Company expressly acknowledge that this Agreement is intended to include in its effect, without limitation, all Claims which are known and all Claims which you or the Company do not know or suspect to exist in your or the Company’s favor at the time of execution of this Agreement and that this Agreement contemplates the extinguishment of all such Claims.

FOUR: The parties acknowledge that they might hereafter discover facts different from, or in addition to, those they now know or believe to be true with respect to a Claim or Claims released herein, and they expressly agree to assume the risk of possible discovery of additional or different facts, and agree that this Agreement shall be and remain effective, in all respects, regardless of such additional or different discovered facts.

FIVE: You hereby represent and acknowledge that you have not filed any Claim of any kind against the Company or others released in this Agreement. You further hereby expressly agree never to initiate against the Company or others released in this Agreement any administrative proceeding, lawsuit or any other legal or equitable proceeding of any kind asserting any Claims that are released in this Agreement.

The Company hereby represents and acknowledges that it has not filed any Claim of any kind against you or others released in this Agreement. The Company further hereby expressly agrees never to initiate against you or others released in this Agreement any administrative proceeding, lawsuit or any other legal or equitable proceeding of any kind asserting any Claims that are released in this Agreement.

SIX: You hereby represent and agree that you have not assigned or transferred, or attempted to have assigned or transfer, to any person or entity, any of the Claims that you are releasing in this Agreement.

The Company hereby represents and agrees that it has not assigned or transferred, or attempted to have assigned or transfer, to any person or entity, any of the Claims that it is releasing in this Agreement.

SEVEN: As a further material inducement to the Company to enter into this Agreement, you hereby agree to indemnify and hold each of the Releasees harmless from all loss, costs, damages, or expenses, including without limitation, attorneys’ fees incurred by the Releasees, arising out of any breach of this Agreement by you or the fact that any representation made in this Agreement by you was false when made.

As a further material inducement to you to enter into this Agreement, the Company hereby agrees to indemnify and hold each of the Releasees harmless from all loss, costs, damages, or expenses, including without limitation, attorneys’ fees incurred by the Releasees, arising out of any breach of this Agreement by it or the fact that any representation made in this Agreement by it was knowingly false when made.

EIGHT: You and the Company represent and acknowledge that in executing this Agreement, neither is relying upon any representation or statement not set forth in this Agreement or the Severance Agreement.

NINE:

(a) This Agreement shall not in any way be construed as an admission by the Company that it has acted wrongfully with respect to you or any other person, or that you have any rights whatsoever against the Company, and the Company specifically disclaims any liability to or wrongful acts against you or any other person, on the part of itself, its employees or its agents. This Agreement shall not in any way be construed as an admission by you that you have acted wrongfully with respect to the Company, or that you failed to perform your duties or negligently performed or breached your duties, or that the Company had good cause to terminate your employment.

(b) If you are a party or are threatened to be made a party to any proceeding by reason of the fact that you were an officer or director of the Company, the Company shall indemnify you against any expenses (including reasonable attorneys’ fees; provided, that counsel has been approved by the Company prior to retention, which approval shall not be unreasonably withheld), judgments, fines, settlements and other amounts actually or reasonably incurred by you in connection with that proceeding; provided, that you acted in good faith and in a manner you reasonably believed to be in the best interest of the Company. The limitations of California Corporations Code Section 317 shall apply to this assurance of indemnification.

(c) You agree to cooperate with the Company and its designated attorneys, representatives and agents in connection with any actual or threatened judicial, administrative or other legal or equitable proceeding in which the Company is or may become involved. Upon reasonable notice, you agree to meet with and provide to the Company or its designated attorneys, representatives or agents all information and knowledge you have relating to the subject matter of any such proceeding. The Company agrees to reimburse you for any reasonable costs you incur in providing such cooperation.

TEN: This Agreement is made and entered into in California. This Agreement shall in all respects be interpreted, enforced and governed by and under the laws of the State of California and applicable Federal law. Any dispute about the validity, interpretation, effect or alleged violation of this Agreement (an “arbitrable dispute”) must be submitted to arbitration in San Diego, California. Arbitration shall take place before an experienced employment arbitrator licensed to practice law in such state and selected in accordance with the then existing JAMS arbitration rules applicable to employment disputes; provided, however, that in any event, the arbitrator shall allow reasonable discovery. Arbitration shall be the exclusive remedy for any arbitrable dispute. The arbitrator in any arbitrable dispute shall not have authority to modify or change the Agreement in any respect. You and the Company shall each be responsible for payment of one-half (1/2) the amount of the arbitrator’s fee(s); provided, however, that in no event shall you be required to pay any fee or cost of arbitration that is unique to arbitration or exceeds the costs you would have incurred had any arbitrable dispute been pursued in a court of competent jurisdiction. The Company shall make up any shortfall. Should any party to this Agreement institute any legal action or administrative proceeding against the other with respect to any Claim waived by this Agreement or pursue any arbitrable dispute by any method other than arbitration, the prevailing party shall be entitled to recover from the non-prevailing party all damages, costs, expenses and attorneys’ fees incurred as a result of that action. The arbitrator’s decision and/or award shall be rendered in writing and will be fully enforceable and subject to an entry of judgment by the Superior Court of the State of California for the County of San Diego, or any other court of competent jurisdiction.

ELEVEN: Both you and the Company understand that this Agreement is final and binding eight (8) days after its execution and return. Should you nevertheless attempt to challenge the enforceability of this Agreement as provided in Paragraph TEN or, in violation of that Paragraph, through litigation, as a further limitation on any right to make such a challenge, you shall initially tender to the Company, by certified check delivered to the Company, all monies received pursuant to Section 14(d) of the Severance Pay Agreement, plus interest, and invite the Company to retain such monies and agree with you to cancel this Agreement and void the Company’s obligations under Section 14(d) of the Severance Pay Agreement. In the event the Company accepts this offer, the Company shall retain such monies and this Agreement shall be canceled and the Company shall have no obligation under Section 14(d) of the Severance Pay Agreement. In the event the Company does not accept such offer, the Company shall so notify you and shall place such monies in an interest-bearing escrow account pending resolution of the dispute between you and the Company as to whether or not this Agreement and the Company’s obligations under Section 14(d) of the Severance Pay Agreement shall be set aside and/or otherwise rendered voidable or unenforceable. Additionally, any consulting agreement then in effect between you and the Company shall be immediately rescinded with no requirement of notice.

TWELVE: Any notices required to be given under this Agreement shall be delivered either personally or by first class United States mail, postage prepaid, addressed to the respective parties as follows:

To Company: [TO COME]

Attn: [TO COME]

To You: ______________________

______________________

THIRTEEN: You understand and acknowledge that you have been given a period of forty-five (45) days to review and consider this Agreement (as well as statistical data on the persons eligible for similar benefits) before signing it and may use as much of this forty-five (45) day period as you wish prior to signing. You are encouraged, at your personal expense, to consult with an attorney before signing this Agreement. You understand and acknowledge that whether or not you do so is your decision. You may revoke this Agreement within seven (7) days of signing it. If you wish to revoke, the Company’s Vice President, Human Resources must receive written notice from you no later than the close of business on the seventh (7th) day after you have signed the Agreement. If revoked, this Agreement shall not be effective and enforceable, and you will not receive payments or benefits under Section 14(d) of the Severance Pay Agreement.

FOURTEEN: This Agreement constitutes the entire agreement of the parties hereto and supersedes any and all other agreements (except the Severance Pay Agreement) with respect to the subject matter of this Agreement, whether written or oral, between you and the Company. All modifications and amendments to this Agreement must be in writing and signed by the parties.

FIFTEEN: Each party agrees, without further consideration, to sign or cause to be signed, and to deliver to the other party, any other documents and to take any other action as may be necessary to fulfill the obligations under this Agreement.

SIXTEEN: If any provision of this Agreement or the application thereof is held invalid, the invalidity shall not affect other provisions or applications of the Agreement which can be given effect without the invalid provisions or application; and to this end the provisions of this Agreement are declared to be severable.

SEVENTEEN: This Agreement may be executed in counterparts.

I have read the foregoing General Release, and I accept and agree to the provisions it contains and hereby execute it voluntarily and with full understanding of its consequences. I am aware it includes a release of all known or unknown claims.

DATED: __________

__________________________________________

DATED: __________

__________________________________________

You acknowledge that you first received this Agreement on [date].

_________________________

Exhibit 10.64

SEMPRA ENERGY

SEVERANCE PAY AGREEMENT

THIS AGREEMENT (this “Agreement”), dated as of August 30, 2014, (the “Effective Date”) is made by and between SEMPRA ENERGY, a California corporation (“Sempra Energy”), and Sharon Tomkins (the “Executive”).

WHEREAS, Sempra Energy and the Executive desire to enter into this Agreement; and

WHEREAS, the Board of Directors of Sempra Energy (the “Board”) has authorized this Agreement.

NOW, THEREFORE, in consideration of the premises and mutual covenants herein contained, the Company and the Executive hereby agree as follows:

Section 1. Definitions

. For purposes of this Agreement, the following capitalized terms have the meanings set forth below:

“Accounting Firm” has the meaning assigned thereto in Section 8(d) hereof.

“Accrued Obligations" means the sum of (A) the Executive’s Annual Base Salary through the Date of Termination to the extent not theretofore paid, (B) an amount equal to any annual Incentive Compensation Awards earned with respect to fiscal years ended prior to the year that includes the Date of Termination to the extent not theretofore paid, (C) any accrued and unpaid vacation, if any, and (D) reimbursement for unreimbursed business expenses, if any, properly incurred by the Executive in the performance of his duties in accordance with policies established from time to time by the Board, in each case to the extent not theretofore paid.

“Affiliate” has the meaning set forth in Rule 12b-2 promulgated under the Exchange Act.

“Annual Base Salary” means the Executive’s annual base salary from the Company.

“Asset Purchaser” has the meaning assigned thereto in Section 16(e).

“Asset Sale” has the meaning assigned thereto in Section 16(e).

“Average Annual Bonus” means the average of the annual bonuses from the Company earned by the Executive with respect to the three (3) fiscal years of the Company immediately preceding the Date of Termination (the “Bonus Fiscal Years”); provided, however, that, if the Executive was employed by the Company for less than three (3) years of the Bonus Fiscal Years, “Average Annual Bonus” means the average of the annual bonuses (if any) from the Company earned by the Executive with respect to the Bonus Fiscal Years during which the Executive was employed by the Company; and, provided, further, that, if the Executive was not employed by the Company during any portion of any of the Bonus Fiscal Years, “Average Annual Bonus” means zero.

“Cause” means:

(b) From and after a Change in Control, (i) the willful and continued failure by the Executive to substantially perform the Executive’s duties with the Company (other than any such failure resulting from the Executive’s incapacity due to physical or mental illness or any such actual or anticipated failure after the issuance of a Notice of Termination for Good Reason by the Executive pursuant to Section 2 hereof) and/or (ii) the Executive’s commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty. For purposes of clause (i) of this subsection (b), no act, or failure to act, on the Executive’s part shall be deemed “willful” unless done, or omitted to be done, by the Executive not in good faith and without reasonable belief that the Executive’s act, or failure to act, was in the best interests of the Company. Notwithstanding the foregoing, the Executive shall not be deemed terminated for Cause pursuant to clause (i) of this subsection (b) unless and until the Executive shall have been provided with reasonable notice of and, if possible, a reasonable opportunity to cure the facts and circumstances claimed to provide a basis for termination of the Executive’s employment for Cause.

(ii) a “change in the effective control of Sempra Energy” occurs only on either of the following dates:

(b) A “change in the ownership of Sempra Energy” or “a change in the effective control of Sempra Energy” shall not occur under clause (a)(i) or (a)(ii) by reason of any of the following:

(i) an acquisition of ownership of stock of Sempra Energy directly from Sempra Energy or its Affiliates other than in connection with the acquisition by Sempra Energy or its Affiliates of a business,

(iii) a merger or consolidation effected to implement a recapitalization of Sempra Energy (or similar transaction) in which no Person is or becomes the Beneficial Owner (within the meaning of Rule 13d-3 promulgated under the Exchange Act, directly or indirectly, of securities of Sempra Energy (not including the securities beneficially owned by such Person any securities acquired directly from Sempra Energy or its Affiliates other than in connection with the acquisition by Sempra Energy or its Affiliates of a business) representing twenty percent (20%) or more of the combined voting power of Sempra Energy’s then outstanding securities.

“Change in Control Date” means the date on which a Change in Control occurs.

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

“Compensation Committee” means the compensation committee of the Board.

“Consulting Payment” has the meaning assigned thereto in Section 14(d) hereof.

“Consulting Period” has the meaning assigned thereto in Section 14(e) hereof.

“Date of Termination” has the meaning assigned thereto in Section 2(b) hereof.

“Deferred Compensation Plan” has the meaning assigned thereto in Section 4(f) hereof.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the applicable rulings and regulations thereunder.

“Excise Tax” has the meaning assigned thereto in Section 8(a) hereof.

“Good Reason” means:

(vi) the failure by Sempra Energy to perform its obligations under Section 16(c), (d) or (e) hereof;

(vii) the failure by the Company to provide the indemnification and D&O insurance protection Section 10 of this Agreement requires it to provide; or

(viii) the failure by Sempra Energy to comply with any material provision of this Agreement.

(i) an adverse change in the Executive’s title, authority, duties, responsibilities or reporting lines as in effect immediately prior to the Change in Control;

(vi) the failure by Sempra Energy to perform its obligations under Section 16(c), (d) or (e) hereof;

(vii) the failure by the Company to provide the indemnification and D&O insurance protection Section 10 of this Agreement requires it to provide; or

(viii) the failure by Sempra Energy to comply with any material provision of this Agreement.

“Involuntary Termination” means (a) the Executive’s Separation from Service by reason other than for Cause, death, Disability or Mandatory Retirement, or (b) the Executive’s Separation from Service by reason of resignation of employment for Good Reason.

“JAMS Rules” has the meaning assigned thereto in Section 13 hereof.

“Mandatory Retirement” means termination of employment pursuant to the Company’s mandatory retirement policy.

“Notice of Termination” has the meaning assigned thereto in Section 2(a) hereof.

“Payment” has the meaning assigned thereto in Section 8(a) hereof.

“Payment in Lieu of Notice” has the meaning assigned thereto in Section 2(b) hereof.

“Post-Change in Control Severance Payment” has the meaning assigned thereto in Section 5 hereof.

“Pre-Change in Control Severance Payment” has the meaning assigned thereto in Section 4 hereof.

“Principal Location” has the meaning assigned thereto in clause (b)(iii) of the definition of Good Reason, above.

“Proprietary Information” has the meaning assigned thereto in Section 14(a) hereof.

“Pro Rata Bonus” has the meaning assigned thereto in Section 5(b).

“Release” has the meaning assigned thereto in Section 4 hereof.

“Section 409A Payments” means any of the following: (a) the Payment in Lieu of Notice; (b) the Pre-Change in Control Severance Payment; (c) the Post-Change in Control Severance Payment; (d) the Pro Rata Bonus; (e) the Consulting Payment; (f) the financial planning services and the related payments provided under Sections 4(e) and 5(f); (g) the legal fees and expenses reimbursed under Section 15; and (h) any other payment that the Company determines in its sole discretion is subject to Section 409A of the Code as non-qualified deferred compensation.

“Separation from Service” has the meaning set forth in Treasury Regulation Section 1.409A-1(h).

“Specified Employee” shall be determined in accordance with Section 409A(a)(2)(B)(i) of the Code and Treasury Regulation Section 1.409A-1(i).

For purposes of this Agreement, references to any “Treasury Regulation” shall mean such Treasury Regulation as in effect on the date hereof.

Section 2. Notice and Date of Termination

(b) The date of the Executive’s termination of employment with the Company (the “Date of Termination”) shall be determined as follows: (i) if the Executive’s Separation from Service is at the volition of the Company, then the Date of Termination shall be the date specified in the Notice of Termination (which, in the case of a termination by the Company other than for Cause, shall not be less than two (2) weeks from the date such Notice of Termination is given unless the Company elects to pay the Executive, in addition to any other amounts payable hereunder, an amount (the “Payment in Lieu of Notice”) equal to two (2) weeks of the Executive’s Annual Base Salary in effect on the Date of Termination), and (ii) if the Executive’s Separation from Service is by the Executive for Good Reason, the Date of Termination shall be determined by the Executive and specified in the Notice of Termination, but in no event less than fifteen (15) days nor more than sixty (60) days after the date such Notice of Termination is given. The Payment in Lieu of Notice shall be paid on such date as is required by law, but no later than thirty (30) days after the date of the Executive’s Separation from Service; provided, however, that if the Executive is a Specified Employee on the date of his or her Separation from Service, such Payment in Lieu of Notice shall be paid as provided in Section 9 hereof.

Section 3. Termination from the Board. Upon the termination of the Executive’s employment for any reason, the Executive’s membership on the Board, the board of directors of any of the Company’s Affiliates, any committees of the Board and any committees of the board of directors of any of the Company’s Affiliates, if applicable, shall be automatically terminated.

Section 4. Severance Benefits upon Involuntary Termination Prior to Change in Control

. Except as provided in Section 5(g) and Section 19(i) hereof, in the event of the Involuntary Termination of the Executive prior to a Change in Control, the Company shall pay the Executive, in one lump sum cash payment, an amount (the “Pre-Change in Control Severance Payment”) equal to one-half (0.5) times the greater of: (X) 145% of the Executive’s Annual Base Salary as in effect on the Date of Termination, and (Y) the Executive’s Annual Base Salary as in effect on the Date of Termination, plus the Executive’s Average Annual Bonus. In addition to the Pre-Change in Control Severance Payment, the Executive shall be entitled to the following additional benefits specified in subsections (a) through (e). The Company's obligation to pay the Pre-Change in Control Severance Payment or provide the benefits set forth in subsections (c), (d) and (e) are subject to and conditioned upon the Executive executing a release (the “Release”) of all claims substantially in the form attached hereto as Exhibit A within fifty (50) days after the date of Involuntary Termination and Executive not revoking such Release in accordance with the terms thereof. Except as provided in Section 4(f), the Pre-Change in Control Severance Payment shall be paid on such date as is determined by the Company within sixty (60) days after the date of the Involuntary Termination; but not before the Release becomes effective and irrevocable. If the fifty (50) day period in which the Release could become effective spans more than one taxable year, then the Pre-Change in Control Severance Payment shall not be made until the later taxable year. Notwithstanding the foregoing, if the Executive is a Specified Employee on the date of the Executive’s Involuntary Termination, the Pre-Change in Control Severance Payment and the financial planning services and the related payments provided under Section 4(e) shall be paid as provided in Section 9 hereof.

(a) Accrued Obligations. The Company shall pay the Executive a lump sum amount in cash equal to the Accrued Obligations within the time required by law.

(b) Equity Based Compensation. The Executive shall retain all rights to any equity-based compensation awards to the extent set forth in the applicable plan and/or award agreement.

(c) Welfare Benefits. Subject to Section 12 below, for a period of six (6) months following the date of the Involuntary Termination (and an additional six (6) months if the Executive provides consulting services under Section 14(e) hereof), the Executive and his dependents shall be provided with health insurance benefits substantially similar to those provided to the Executive and his dependents immediately prior to the date of the Involuntary Termination; provided, however, that such benefits shall be provided on substantially the same terms and conditions and at the same cost to the Executive as in effect immediately prior to the date of the Involuntary Termination. Such benefits shall be provided through insurance maintained by the Company under the Company’s benefit plans. Such benefits shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(a)(5). Notwithstanding the foregoing, if the Company determines in its sole discretion that it cannot provide the foregoing benefit without potentially violating applicable law (including, without limitation, Section 2716 of the Public Health Service Act), the Company shall in lieu thereof provide to the Executive a taxable monthly payment in an amount equal to the monthly premium that the Executive would be required to pay to continue the Executive’s and his covered dependents’ group insurance coverages under COBRA as in effect on the Date of Termination (which amount shall be based on the premiums for the first month of COBRA coverage); provided, however, that, if the Executive is a Specified Employee on the Date of Termination, then such payments shall be paid as provided in Section 9 hereof.

(e) Financial Planning Services. The Executive shall receive financial planning services, on an in-kind basis, for a period of twelve (12) months following the Date of Termination. Such financial planning services shall include expert financial and legal resources to assist the Executive with financial planning needs and shall be limited to (i) current investment portfolio management, (ii) tax planning, (iii) tax return preparation, and (iv) estate planning advice and document preparation (including wills and trusts); provided, however, that the Company shall provide such financial planning services during any taxable year of the Executive only to the extent the cost to the Company for such taxable year does not exceed [$25,000]. The Company shall provide such financial planning services through a financial planner selected by the Company, and shall pay the fees for such financial planning services. The financial planning services provided during any taxable year of the Executive shall not affect the financial planning services provided in any other taxable year of the Executive. The Executive’s right to financial planning services shall not be subject to liquidation or exchange for any other benefit. Such financial planning services shall be provided in a manner that complies with Treasury Regulation Section 1.409A-3(i)(1)(iv).

(f) Deferral of Payments. The Executive shall have the right to elect to defer the Pre-Change in Control Severance Payment to be received by the Executive pursuant to this Section 4 under the terms and conditions of the Sempra Energy 2005 Deferred Compensation Plan (the “Deferred Compensation Plan”). Any such deferral election shall be made in accordance with Section 18(b) hereof.

Section 5. Severance Benefits upon Involuntary Termination in Connection with and after Change in Control

. Notwithstanding the provisions of Section 4 above, and except as provided in Section 19(i) hereof, in the event of the Involuntary Termination of the Executive on or within two (2) years following a Change in Control, in lieu of the payments described in Section 4 above, the Company shall pay the Executive, in one lump sum cash payment, an amount (the “Post-Change in Control Severance Payment”) equal to the greater of: (X) 145% of the Executive’s Annual Base Salary as in effect immediately prior to the Change in Control or the Date of Termination, whichever is greater, and (Y) the Executive’s Annual Base Salary as in effect immediately prior to the Change in Control or on the Date of Termination, whichever is greater, plus the Executive’s Average Annual Bonus; provided, however, that, in the event that the Involuntary Termination occurs prior to the fifth anniversary of the Effective Date, the Post-Change in Control Severance Payment shall be increased by twenty-five percent (25%). In addition to the Post-Change in Control Severance Payment, the Executive shall be entitled to the benefits specified in subsections (a) through (f). The Company's obligation to pay the Post-Change in Control Severance Payment or provide the benefits set forth in subsections (b), (c), (d), (e) and (f) are subject to and conditioned upon the Executive executing the Release within fifty (50) days after the date of Involuntary Termination and Executive not revoking such Release in accordance with the terms thereof. Except as provided in Sections 5(g) and 5(h), the Post-Change in Control Severance Payment, and the Pro Rata Bonus shall be paid on such date as is determined by the Company within sixty (60) days after the date of the Involuntary Termination. If the fifty (50) day period in which the Release could become effective spans more than one taxable year, then the Post-Change in Control Severance Payment and Pro Rata Bonus shall not be made until the later taxable year. Notwithstanding the foregoing, if the Executive is a Specified Employee on the date of the Executive’s Involuntary Termination, the Post-Change in Control Severance Payment, the Pro Rata Bonus and the financial planning services and the related payments provided under Section 5(f) shall be paid as provided in Section 9 hereof.

(a) Accrued Obligations. The Company shall pay the Executive a lump sum amount in cash equal to the Executive's Accrued Obligations within the time required by law.

(b) Pro Rata Bonus. The Company shall pay the Executive a lump sum amount in cash equal to: (i) the greater of: (X) 45% of the Executive’s Annual Base Salary as in effect immediately prior to the Change in Control or on the Date of Termination, whichever is greater, or (Y) the Executive’s Average Annual Bonus, multiplied by (ii) a fraction, the numerator of which shall be the number of days from the beginning of such fiscal year to and including the Date of Termination and the denominator of which shall be 365 equal to the (“Pro Rata Bonus”).

(c) Equity-Based Compensation. Notwithstanding the provisions of any applicable equity-compensation plan or award agreement to the contrary, all equity-based Incentive Compensation Awards (including, without limitation, stock options, stock appreciation rights, restricted stock awards, restricted stock units, performance share awards, awards covered under Section 162(m) of the Code, and dividend equivalents) held by the Executive shall immediately vest and become exercisable or payable, as the case may be, as of the Date of Termination, to be exercised or paid, as the case may be, in accordance with the terms of the applicable Incentive Compensation Plan and Incentive Compensation Award agreement, and any restrictions on any such Incentive Compensation Awards shall automatically lapse; provided, however, that any such stock option or stock appreciation rights awards granted on or after June 26, 1998 shall remain outstanding and exercisable until the earlier of (A) the later of eighteen (18) months following the Date of Termination or the period specified in the applicable Incentive Compensation Award agreements or (B) the expiration of the original term of such Incentive Compensation Award (or, if earlier, the tenth anniversary of the original date of grant) (it being understood that all Incentive Compensation Awards granted prior to or after June 26, 1998 shall remain outstanding and exercisable for a period that is no less than that provided for in the applicable agreement in effect as of the date of grant).

(d) Welfare Benefits. Subject to Section 12 below, for a period of six (6) months following the date of Involuntary Termination (and an additional twelve (12) months if the Executive provides consulting services under Section 14(e) hereof), the Executive and his dependents shall be provided with life, disability, accident and health insurance benefits substantially similar to those provided to the Executive and his dependents immediately prior to the date of Involuntary Termination or the Change in Control Date, whichever is more favorable to the Executive; provided, however, that such benefits shall be provided on substantially the same terms and conditions and at the same cost to the Executive as in effect immediately prior to the date of Involuntary Termination or the Change in Control Date, whichever is more favorable to the Executive. Such benefits shall be provided through insurance maintained by the Company under the Company benefit plans. Such benefits shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(a)(5). Notwithstanding the foregoing, if the Company determines in its sole discretion that it cannot provide the foregoing benefit without potentially violating applicable law (including, without limitation, Section 2716 of the Public Health Service Act), the Company shall in lieu thereof provide to the Executive a taxable monthly payment in an amount equal to the monthly premium that the Executive would be required to pay to continue the Executive’s and his covered dependents’ group insurance coverages under COBRA as in effect on the Date of Termination (which amount shall be based on the premiums for the first month of COBRA coverage); provided, however, that, if the Executive is a Specified Employee on the Date of Termination, then such payments shall be paid as provided in Section 9 hereof.

(e) Outplacement Services. The Executive shall receive reasonable outplacement services, on an in-kind basis, suitable to his position and directly related to the Executive’s Involuntary Termination, for a period of eighteen (18) months following the date of Involuntary Termination (but in no event beyond the last day of the Executive’s second taxable year following the Executive’s taxable year in which the Involuntary Termination occurs), in the aggregate amount of cost to the Company not to exceed $50,000. Notwithstanding the foregoing, the Executive shall cease to receive outplacement services on the date the Executive accepts employment with a subsequent employer. Such outplacement services shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(b)(9)(v)(A).

(f) Financial Planning Services. The Executive shall receive financial planning services, on an in-kind basis, for a period of eighteen (18) months following the date of Involuntary Termination. Such financial planning services shall include expert financial and legal resources to assist the Executive with financial planning needs and shall be limited to (i) current investment portfolio management, (ii) tax planning, (iii) tax return preparation, and (iv) estate planning advice and document preparation (including wills and trusts); provided, however, that the Company shall provide such financial services during any taxable year of the Executive only to the extent the cost to the Company for such taxable year does not exceed [$25,000]. The Company shall provide such financial planning services through a financial planner selected by the Company, and shall pay the fees for such financial planning services. The financial planning services provided during any taxable year of the Executive shall not affect the financial planning services provided in any other taxable year of the Executive. The Executive’s right to financial planning services shall not be subject to liquidation or exchange for any other benefit. Such financial planning services shall be provided in a manner that complies with Section 1.409A-3(i)(1)(iv).

(g) Involuntary Termination in Connection with a Change in Control. Notwithstanding anything contained herein, in the event of an Involuntary Termination prior to a Change in Control, if the Involuntary Termination (1) was at the request of a third party who has taken steps reasonably calculated to effect such Change in Control or (2) otherwise arose in connection with or in anticipation of such Change in Control, then the Executive shall, in lieu of the payments described in Section 4 hereof, be entitled to the Post-Change in Control Severance Payment and the additional benefits described in this Section 5 as if such Involuntary Termination had occurred within two (2) years following the Change in Control. The amounts specified in Section 5 that are to be paid under this Section 5(g) shall be reduced by any amount previously paid under Section 4. The amounts to be paid under this Section 5(g) shall be paid within sixty (60) days after the Change in Control Date of such Change in Control.

(h) Deferral of Payments. The Executive shall have the right to elect to defer the Post-Change in Control Severance Payment and the Pro Rata Bonus to be received by the Executive pursuant to this Section 5 under the terms and conditions of the Deferred Compensation Plan. Any such deferral election shall be made in accordance with Section 18(b) hereof.

Section 6. Severance Benefits upon Termination by the Company for Cause or by the Executive Other than for Good Reason. If the Executive’s employment shall be terminated for Cause, or if the Executive terminates employment other than for Good Reason, the Company shall have no further obligations to the Executive under this Agreement other than the Accrued Obligations and any amounts or benefits described in Section 10 hereof.

Section 7. Severance Benefits upon Termination due to Death or Disability. If the Executive has a Separation from Service by reason of death or Disability, the Company shall pay the Executive or his estate, as the case may be, the Accrued Obligations and the Pro Rata Bonus (without regard to whether a Change in Control has occurred) and any amounts or benefits described in Section 10 hereof. Such payments shall be in addition to those rights and benefits to which the Executive or his estate may be entitled under the relevant Company plans or programs. The Company's obligation to pay the Pro Rata Bonus is conditioned upon the Executive, the Executive's representative or the Executive's estate, as the case may be executing the Release within fifty (50) days after the date of Executive's Separation from Service and not revoking such Release in accordance with the terms thereof. The Accrued Obligations shall be paid within the time required by law and the Pro Rata Bonus shall be paid on such date as determined by the Company within sixty (60) days after the date of the Separation from Service but not before the Release becomes effective and irrevocable. If the fifty (50) day period in which the Release could become effective spans more than one taxable year, then the Pro Rata Bonus shall not be made until the later taxable year. Notwithstanding the foregoing, if the Executive is a Specified Employee on the date of the Executive’s Separation from Service, the Pro Rata Bonus shall be paid as provided in Section 9 hereof.

Section 8. Limitation on Payments by the Company.

(a) Anything in this Agreement to the contrary notwithstanding and except as set forth in this Section 8 below, in the event it shall be determined that any payment or distribution in the nature of compensation (within the meaning of Section 280G(b)(2) of the Code) to or for the benefit of the Executive, whether paid or payable pursuant to this Agreement or otherwise (the “Payment”) would be subject (in whole or in part) to the excise tax imposed by Section 4999 of the Code, (the “Excise Tax”), then, subject to subsection (b), the Pre-Change in Control Severance Benefit or the Post-Change in Control Severance Payment (whichever is applicable) payable under this Agreement shall be reduced under this subsection (a) to the amount equal to the Reduced Payment. For such Payment payable under this Agreement, the “Reduced Payment” shall be the amount equal to the greatest portion of the Payment (which may be zero) that, if paid, would result in no portion of any Payment being subject to the Excise Tax.

(b) The Pre-Change in Control Severance Benefit or the Post-Change in Control Severance Payment (whichever is applicable) payable under this Agreement shall not be reduced under subsection (a) if:

(i) such reduction in such Payment is not sufficient to cause no portion of any Payment to be subject to the Excise Tax, or

(ii) the Net After-Tax Unreduced Payments (as defined below) would equal or exceed one hundred and five percent (105%) of the Net After-Tax Reduced Payments (as defined below).

(d) All determinations required to be made under this Section 8 and the assumptions to be utilized in arriving at such determinations, shall be made by a nationally recognized accounting firm as may be agreed by the Company and the Executive (the “Accounting Firm”); provided, that the Accounting Firm’s determination shall be made based upon “substantial authority” within the meaning of Section 6662 of the Code. The Accounting Firm shall provide detailed supporting calculations to both the Company and the Executive within fifteen (15) business days of the receipt of notice from the Executive that there has been a Payment or such earlier time as is requested by the Company. All fees and expenses of the Accounting Firm shall be borne solely by the Company. Any determination by the Accounting Firm shall be binding upon the Company and the Executive. For purposes of determining whether and the extent to which the Payments will be subject to the Excise Tax, (i) no portion of the Payments the receipt or enjoyment of which the Executive shall have waived at such time and in such manner as not to constitute a “payment” within the meaning of Section 280G(b) of the Code shall be taken into account, (ii) no portion of the Payments shall be taken into account which, in the written opinion of the Accounting Firm, does not constitute a “parachute payment” within the meaning of Section 280G(b)(2) of the Code (including by reason of Section 280G(b)(4)(A) of the Code) and, in calculating the Excise Tax, no portion of such Payments shall be taken into account which, in the opinion of the Accounting Firm, constitutes reasonable compensation for services actually rendered, within the meaning of Section 280G(b)(4)(B) of the Code, in excess of the base amount (as defined in Section 280G(b)(3) of the Code) allocable to such reasonable compensation, and (iii) the value of any non-cash benefit or any deferred payment or benefit included in the Payments shall be determined by the Accounting Firm in accordance with the principles of Sections 280G(d)(3) and (4) of the Code.

Section 9. Delayed Distribution under Section 409A of the Code. If the Executive is a Specified Employee on the date of the Executive’s Involuntary Termination (or on the date of the Executive’s Separation from Service by reason of Disability), the Section 409A Payments, and any other payments or benefits under this Agreement subject to Section 409A of the Code, shall be delayed in order to avoid a prohibited distribution under Section 409A(a)(2)(B)(i) of the Code, and such payments or benefits shall be paid or distributed to the Executive during the thirty (30) day period commencing on the earlier of (a) the expiration of the six-month period measured from the date of the Executive’s Separation from Service or (b) the date of the Executive’s death. Upon the expiration of the applicable six-month period under Section 409A(a)(2)(B)(i) of the Code, all payments deferred pursuant to this Section 9 (excluding in-kind benefits) shall be paid in a lump sum payment to the Executive, plus interest thereon from the date of the Executive’s Involuntary Termination through the payment date at an annual rate equal to Moody’s Rate. The “Moody’s Rate” shall mean the average of the daily Moody’s Corporate Bond Yield Average – Monthly Average Corporates as published by Moody’s Investors Service, Inc. (or any successor) for the month next preceding the Date of Termination. Any remaining payments due under the Agreement shall be paid as otherwise provided herein.

Section 10. Nonexclusivity of Rights. Nothing in this Agreement shall prevent or limit the Executive’s continuing or future participation in any benefit, plan, program, policy or practice provided by the Company and for which the Executive may qualify (except with respect to any benefit to which the Executive has waived his rights in writing), including, without limitation, any and all indemnification arrangements in favor of the Executive (whether under agreements or under the Company’s charter documents or otherwise), and insurance policies covering the Executive, nor shall anything herein limit or otherwise affect such rights as the Executive may have under any other contract or agreement entered into after the Effective Date with the Company. Amounts which are vested benefits or which the Executive is otherwise entitled to receive under any benefit, plan, policy, practice or program of, or any contract or agreement entered into with, the Company shall be payable in accordance with such benefit, plan, policy, practice or program or contract or agreement except as explicitly modified by this Agreement. At all times during the Executive’s employment with the Company and thereafter, the Company shall provide (to the extent permissible under applicable law) the Executive with indemnification and D&O insurance insuring the Executive against insurable events which occur or have occurred while the Executive was a director or the Executive officer of the Company, on terms and conditions that are at least as generous as that then provided to any other current or former director or the Executive officer of the Company or any Affiliate. Such indemnification and D&O insurance shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(b)(10).

Section 11. Clawbacks. Notwithstanding anything herein to the contrary, if the Company determines, in its good faith judgment, that if the Executive is required to forfeit or to make any repayment of any compensation or benefit(s) to the Company under the Sarbanes-Oxley Act of 2002 or pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act or any other law, such forfeiture or repayment shall not constitute Good Reason.

Section 13. Dispute Resolution.

(a) If any dispute arises between Executive and the Company, including, but not limited to, disputes relating to or arising out of this Agreement, any action relating to or arising out of my employment or its termination, and/or any disputes regarding the interpretation, enforceability, or validity of this Agreement (“Arbitrable Dispute”), Executive and the Company waive the right to resolve the dispute through litigation in a judicial forum and agree to resolve the Arbitrable Dispute through final and binding arbitration, except as prohibited by law. Arbitration shall be the exclusive remedy for any Arbitrable Dispute.

(b) As to any Arbitrable Dispute, the Company and Executive waive any right to a jury trial or a court bench trial. The Company and Executive also waive the right to bring, maintain, or participate in any class, collective, or representative proceeding, whether in arbitration or otherwise. Further, Arbitrable Disputes must be brought in the individual capacity of the party asserting the claim, and cannot be maintained on a class, collective, or representative basis.

(c) Arbitration shall take place at the office of the Judicial Arbitration and Mediation Service (“JAMS”) (or, if Executive is employed outside of California, the American Arbitration Association (“AAA”)) nearest to the location where Executive last worked for the Company. Except to the extent it conflicts with the rules and procedures set forth in this Arbitration Agreement, arbitration shall be conducted in accordance with the JAMs Employment Arbitration Rules & Procedures (if Executive is employed outside of California, the AAA Employment Arbitration Rules & Mediation Procedures), copies of which are attached for my reference and available at www.jamsadr.com; tel: 800.352.5267 and www.adr.org; tel: 800.778.7879, before a single experienced, neutral employment arbitrator selected in accordance with those rules.

(d) The Company will be responsible for paying any filing fee and the fees and costs of the arbitrator. Each party shall pay its own attorneys’ fees. However, if any party prevails on a statutory claim that authorizes an award of attorneys’ fees to the prevailing party, or if there is a written agreement providing for attorneys’ fees, the arbitrator may award reasonable attorneys’ fees to the prevailing party, applying the same standards a court would apply under the law applicable to the claim.

(e) The arbitrator shall apply the Federal Rules of Evidence, shall have the authority to entertain a motion to dismiss or a motion for summary judgment by any party, and shall apply the standards governing such motions under the Federal Rules of Civil Procedure. The arbitrator does not have the authority to consider, certify, or hear an arbitration as a class action, collective action, or any other type of representative action. The Company and Executive recognize that this Agreement arises out of or concerns interstate commerce and that the Federal Arbitration Act shall govern the arbitration and shall govern the interpretation or enforcement of this Arbitration Agreement or any arbitration award.

(f) EXECUTIVE ACKNOWLEDGES THAT BY ENTERING INTO THIS AGREEMENT, EXECUTIVE IS WAIVING ANY RIGHT HE OR SHE MAY HAVE TO A TRIAL BY JURY.

Section 14. Executive’s Covenants.

(d) Release; Lump Sum Payment. In the event of the Executive’s Involuntary Termination, if the Executive (i) reconfirms and agrees to abide by the covenants described in Section 14(a) and Section 14(b) above, (ii) executes the Release within fifty (50) days after the date of Involuntary Termination and does not revoke such Release in accordance with the terms thereof, and (iii) agrees to provide the consulting services described in Section 14(e) below, then in consideration for such covenants and consulting services, the Company shall pay the Executive, in one cash lump sum, an amount (the “Consulting Payment”) in cash equal to one-half (0.5) times the greater of: (X) 145% of the Executive’s Annual Base Salary as in effect on the Date of Termination, and (Y) the Executive’s Annual Base Salary as in effect on the Date of Termination, plus the Executive’s Average Annual Bonus. Except as provided in this subsection, the Consulting Payment shall be paid on such date as is determined by the Company within the ten (10) day period commencing on the 60th day after the date of the Executive’s Involuntary Termination; provided, however, that if the Executive is a Specified Employee on the date of the Executive’s Involuntary Termination, the Consulting Payment shall be paid as provided in Section 9 hereof. The Executive shall have the right to elect to defer the Consulting Payment under the terms and conditions of the Company’s Deferred Compensation Plan. Any such deferral election shall be made in accordance with Section 18(b) hereof.

(e) Consulting. If the Executive agrees to the provisions of in Section 14(d) above, then the Executive shall have the obligation to provide consulting services to the Company as an independent contractor, commencing on the Date of Termination and ending on the first anniversary of the Date of Termination (the “Consulting Period”). The Executive shall hold himself available at reasonable times and on reasonable notice to render such consulting services as may be so assigned to him by the Board or the Company’s then Chief Executive Officer; provided, however, that unless the parties otherwise agree, the consulting services rendered by the Executive during the Consulting Period shall not exceed twenty (20) hours each month; and, provided, further, that the consulting services rendered by the Executive during the Consulting Period shall in no event exceed twenty percent (20%) of the average level of services performed by the Executive for the Company over the thirty-six (36) month period immediately preceding the Executive’s Separation from Service (or the full period of services to the Company, if the Executive has been providing services to the Company for less than thirty-six (36) months). The Company agrees to use its best efforts during the Consulting Period to secure the benefit of the Executive’s consulting services so as to minimize the interference with the Executive’s other activities, including requiring the performance of consulting services at the Company’s offices only when such services may not be reasonably performed off-site by the Executive.

Section 15. Legal Fees.

Section 16. Successors.

Section 18. Section 409A of the Code.

(b) Deferral Elections. As provided in Sections 4(f), 5(h) and 14(d), the Executive may elect to defer the Pre-Change in Control Severance Payment, the Post-Change in Control Severance Payment and the Consulting Payment as follows. The Executive’s deferral election shall satisfy the requirements of Treasury Regulation Section 1.409A-2(b) and the terms and conditions of the Deferred Compensation Plan. Such deferral election shall designate the whole percentage (up to a maximum of 100%) of the Pre-Change in Control Severance Payment, the Post-Change in Control Severance Payment and the Consulting Payment to be deferred, shall be irrevocable when made, and shall not take effect until at least twelve (12) months after the date on which the election is made. Such deferral election shall provide that the amount deferred shall be deferred for a period of not less than five (5) years from the date the payment of the amount deferred would otherwise have been made, in accordance with Treasury Regulation Section 1.409A-2(b)(1)(ii).

Section 19. Miscellaneous.

(c) Severability. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement.

(d) Taxes. The Company may withhold from any amounts payable under this Agreement such federal, state or local taxes as shall be required to be withheld pursuant to any applicable law or regulation.

(k) Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument.

IN WITNESS WHEREOF, the Executive and, pursuant to due authorization from its Board of Directors, the Company have caused this Agreement to be executed as of the day and year first above written.

SEMPRA ENERGY

G. Joyce Rowland

Senior Vice President and Chief Human Resources and Administrative Officer

_____________________________________

Date

EXECUTIVE

Sharon Tomkins

Vice President and General Counsel

_____________________________________

Date

EXHIBIT A

GENERAL RELEASE

WHEREAS, you and the Company have previously entered into that certain Severance Pay Agreement dated ____________, 20__ (the “Severance Pay Agreement”); and

WHEREAS, your right to receive certain severance pay and benefits pursuant to the terms of Section 4 or Section 5 of the Severance Pay Agreement, as applicable, are subject to and conditioned upon your execution and non-revocation of a general release of claims by you against the Company and its subsidiaries and affiliates.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, you and the Company hereby agree as follows:

ONE: Your signing of this Agreement confirms that your employment with the Company shall terminate at the close of business on ____________, or earlier upon our mutual agreement.

TWO: As a material inducement for the payment of the severance and benefits under the Severance Pay Agreement, and except as otherwise provided in this Agreement, you and the Company hereby irrevocably and unconditionally release, acquit and forever discharge the other from any and all Claims either may have against the other. For purposes of this Agreement and the preceding sentence, the words “Releasee” or “Releasees” and “Claim” or “Claims” shall have the meanings set forth below:

THREE: You and the Company expressly waive and relinquish all rights and benefits afforded by any statute (including but not limited to Section 1542 of the Civil Code of the State of California and analogous laws of other states) which limits the effect of a release with respect to unknown claims. You and the Company do so understanding and acknowledging the significance of the release of unknown claims and the waiver of statutory protection against a release of unknown claims (including but not limited to Section 1542 and analogous laws of other states). Section 1542 of the Civil Code of the State of California states as follows:

“A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT KNOW OR SUSPECT TO EXIST IN HIS OR HER FAVOR AT THE TIME OF EXECUTING THE RELEASE, WHICH IF KNOWN BY HIM OR HER MUST HAVE MATERIALLY AFFECTED HIS SETTLEMENT WITH THE DEBTOR.”

NINE: (a) This Agreement shall not in any way be construed as an admission by the Company that it has acted wrongfully with respect to you or any other person, or that you have any rights whatsoever against the Company, and the Company specifically disclaims any liability to or wrongful acts against you or any other person, on the part of itself, its employees or its agents. This Agreement shall not in any way be construed as an admission by you that you have acted wrongfully with respect to the Company, or that you failed to perform your duties or negligently performed or breached your duties, or that the Company had good cause to terminate your employment.

TEN: This Agreement is entered into in California and shall be governed by substantive California law, except as provided in this section. If any dispute arises between you and the Company, including but not limited to, disputes relating to this Agreement, or if you prosecute a claim you purported to release by means of this Agreement (“Arbitrable Dispute”), you and the Company agree to resolve that Arbitrable Dispute through final and binding arbitration under this section. You also agree to arbitrate any Arbitrable Dispute which also involves any other released party who offers or agrees to arbitrate the dispute under this section. Your agreement to arbitrate applies, for example, to disputes about the validity, interpretation, or effect of this Agreement or alleged violations of it, claims of discrimination under federal or state law, or other statutory violation claims.

As to any Arbitrable Dispute, you and the Company waive any right to a jury trial or a court bench trial. You and the Company also waive the right to bring, maintain, or participate in any class, collective, or representative proceeding, whether in arbitration or otherwise. Further, Arbitrable Disputes must be brought in the individual capacity of the party asserting the claim, and cannot be maintained on a class, collective, or representative basis.

Arbitration shall take place in San Diego, California under the employment dispute resolution rules of the Judicial Arbitration and Mediation Service (“JAMS”), (or, if you are employed outside of California at the time of the termination of your employment, at the nearest location of the American Arbitration Association and in accordance with the AAA rules), before an experienced employment arbitrator selected in accordance with those rules. The arbitrator may not modify or change this Agreement in any way. The Company will be responsible for paying any filing fee and the fees and costs of the Arbitrator; provided, however, that if you are the party initiating the claim, you will contribute an amount equal to the filing fee to initiate a claim in the court of general jurisdiction in the state in which you are employed by the Company. Each party shall pay for its own costs and attorneys’ fees, if any. However if any party prevails on a statutory claim which affords the prevailing party attorneys’ fees and costs, or if there is a written agreement providing for attorneys’ fees and/or costs, the Arbitrator may award reasonable attorney’s fees and/or costs to the prevailing party, applying the same standards a court would apply under the law applicable to the claim. The Arbitrator shall apply the Federal Rules of Evidence and shall have the authority to entertain a motion to dismiss or a motion for summary judgment by any party and shall apply the standards governing such motions under the Federal Rules of Civil Procedure. The Federal Arbitration Act shall govern the arbitration and shall govern the interpretation or enforcement of this section or any arbitration award. The arbitrator will not have the authority to consider, certify, or hear an arbitration as a class action, collective action, or any other type of representative action.

To the extent that the Federal Arbitration Act is inapplicable, California law pertaining to arbitration agreements shall apply. Arbitration in this manner shall be the exclusive remedy for any Arbitrable Dispute. Except as prohibited by the ADEA, should you or the Company attempt to resolve an Arbitrable Dispute by any method other than arbitration pursuant to this section, the responding party will be entitled to recover from the initiating party all damages, expenses, and attorneys’ fees incurred as a result of this breach. This section TEN supersedes any existing arbitration agreement between the Company and me as to any Arbitrable Dispute. Notwithstanding anything in this section TEN to the contrary, a claim for benefits under an ERISA-covered plan shall not be an Arbitrable Dispute.

ELEVEN: Both you and the Company understand that this Agreement is final and binding eight (8) days after its execution and return. Should you nevertheless attempt to challenge the enforceability of this Agreement as provided in Paragraph TEN or, in violation of that Paragraph, through litigation, as a further limitation on any right to make such a challenge, you shall initially tender to the Company, by certified check delivered to the Company, all monies received pursuant to Sections 4 or 5 of the Severance Pay Agreement, as applicable, plus interest, and invite the Company to retain such monies and agree with you to cancel this Agreement and void the Company’s obligations under of the Severance Pay Agreement. In the event the Company accepts this offer, the Company shall retain such monies and this Agreement shall be canceled and the Company shall have no obligation under of the Severance Pay Agreement. In the event the Company does not accept such offer, the Company shall so notify you and shall place such monies in an interest-bearing escrow account pending resolution of the dispute between you and the Company as to whether or not this Agreement and the Company’s obligations under of the Severance Pay Agreement shall be set aside and/or otherwise rendered voidable or unenforceable. Additionally, any consulting agreement then in effect between you and the Company shall be immediately rescinded with no requirement of notice.

To Company: [TO COME]

Attn: [TO COME]

To You: ______________________

______________________

SEVENTEEN: This Agreement may be executed in counterparts.

DATED: __________

__________________________________________

DATED: __________

__________________________________________

You acknowledge that you first received this Agreement on [date].

_________________________

Exhibit 10.78

AMENDMENT NO. 13

TO THE

SAN DIEGO GAS & ELECTRIC COMPANY

NUCLEAR FACILITIES QUALIFIED CPUC DECOMMISSIONING

MASTER TRUST AGREEMENT

FOR

SAN ONOFRE NUCLEAR GENERATING STATIONS

This Amendment No. 13 made this 1st day of January, 2015, by and between the San Diego Gas & Electric Company (the “Company”) and The Bank of New York Mellon (“Trustee”).

WHEREAS, pursuant to Section 2.12 of the Nuclear Facilities Qualified Decommissioning Master Trust for San Onofre Nuclear Generating Stations dated as of June 29, 1992, as amended (“Agreement”) between the Company and the Trustee, the parties specifically reserved the right to amend the Agreement;

NOW, THEREFORE, the Company and the Trustee agree as follows:

The Fee Schedule attached as Exhibit C to the Agreement is hereby replaced with the revised Fee Schedule attached as Appendix A hereto.

Section 4.09 of Article IV is hereby added as follows:

“Additional Services. The Trustee shall make available a Nuclear Decommissioning Trust expert to present to the San Diego Gas & Electric Nuclear Decommissioning Trust Fund Committee up to twice a year.

The Trustee shall also retain Relationship Executives, Service Directors and Global Risk Solutions (“GRS”) Consultants with no less than ten years of relevant industry experience. If a Relationship Executive, Service Director or GRS Consultant with less experience is being considered, assignment to the relationship will be subject to interview and final approval by the Company.”

Section 4.10 of Article IV is hereby added as follows:

“Performance. The Trustee will prepare (i) an overview of the services to be provided under this Agreement designed to establish mutually agreeable service guidelines (the “Service Level Description”); and (ii) a custom scorecard to measure the Trustee’s monthly performance (the “Scorecard”) in substantially the form attached as Exhibit G to the Service Level Description, and as may be amended from time to time by agreement of Trustee and the Company. In the event that the Trustee materially fails to satisfy the services commitment and standards set forth by the Scorecard, Trustee shall rebate or credit, as the case may be, up to (and not to exceed) $50,000 per year in fees due to Trustee in accordance with the Scorecard. The Trustee shall also conduct a best practices review as set forth in the guidelines attached as Exhibit H to the Service Level Description, and as may be amended from time to time by agreement of Trustee and the Company.”

Each party hereby represents and warrants to the others that it has full authority to enter into this Amendment No. 13 upon the terms and conditions hereof and that the individual executing this Amendment No. 13 on its behalf has the requisite authority to bind that party.

IN WITNESS WHEREOF, the Company, the Trustee, and the California Public Utilities Commission have set their hands and seals in agreement to these amendments effective as provided above.

SAN DIEGO GAS & ELECTRIC COMPANY

By:

________________________________________

Date:

________________________________________

Attest:

________________________________________

THE BANK OF NEW YORK MELLON

By:

________________________________________

Date:

________________________________________

Attest:

________________________________________

CALIFORNIA PUBLIC UTILITIES COMMISSION

By:

________________________________________

Date:

________________________________________

Attest:

________________________________________

Appendix A

Fee Schedule

[ex1078002.gif]

[ex1078004.gif]

[ex1078006.gif]

[ex1078008.gif]

[ex1078010.gif]

[ex1078012.gif]

Exhibit 10.90

AMENDMENT NO. 11

TO THE

SAN DIEGO GAS & ELECTRIC COMPANY

NUCLEAR FACILITIES NON-QUALIFIED CPUC DECOMMISSIONING

MASTER TRUST AGREEMENT

FOR

SAN ONOFRE NUCLEAR GENERATING STATIONS

This Amendment No. 11 made this 1st day of January, 2015, by and between the San Diego Gas & Electric Company (the “Company”) and The Bank of New York Mellon (“Trustee”).

WHEREAS, pursuant to Section 2.10 of the Nuclear Facilities Non-Qualified Decommissioning Master Trust for San Onofre Nuclear Generating Stations dated as of June 29, 1992, as amended (“Agreement”) between the Company and the Trustee, the parties specifically reserved the right to amend the Agreement;

NOW, THEREFORE, the Company and the Trustee agree as follows:

The Fee Schedule attached as Exhibit C to the Agreement is hereby replaced with the revised Fee Schedule attached as Appendix A hereto.

Section 4.09 of Article IV is hereby added as follows:

Section 4.10 of Article IV is hereby added as follows:

“Performance. The Trustee will prepare (i) an overview of the services to be provided under this Agreement designed to establish mutually agreeable service guidelines (the “Service Level Description”); and (ii) a custom scorecard to measure the Trustee’s monthly performance (the “Scorecard”) in substantially the form attached as Exhibit F to the Service Level Description, and as may be amended from time to time by agreement of Trustee and the Company. In the event that the Trustee materially fails to satisfy the services commitment and standards set forth by the Scorecard, Trustee shall rebate or credit, as the case may be, up to (and not to exceed) $50,000 per year in fees due to Trustee in accordance with the Scorecard. The Trustee shall also conduct a best practices review as set forth in the guidelines attached as Exhibit G to the Service Level Description, and as may be amended from time to time by agreement of Trustee and the Company.”

Each party hereby represents and warrants to the others that it has full authority to enter into this Amendment No. 11 upon the terms and conditions hereof and that the individual executing this Amendment No. 11 on its behalf has the requisite authority to bind that party.

IN WITNESS WHEREOF, the Company, the Trustee, and the California Public Utilities Commission have set their hands and seals in agreement to these amendments effective as provided above.

SAN DIEGO GAS & ELECTRIC COMPANY

By:

________________________________________

Date:

________________________________________

Attest:

________________________________________

THE BANK OF NEW YORK MELLON

By:

________________________________________

Date:

________________________________________

Attest:

________________________________________

CALIFORNIA PUBLIC UTILITIES COMMISSION

By:

________________________________________

Date:

________________________________________

Attest:

________________________________________

Appendix A

Fee Schedule

[ex1090002.gif]

[ex1090004.gif]

[ex1090006.gif]

[ex1090008.gif]

[ex1090010.gif]

[ex1090012.gif]

SE Exhibit 12.1



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


			2011		2012		2013		2014		2015
Fixed charges and preferred stock dividends:
Interest		$	549	$	601	$	620	$	636	$	677
Interest portion of annual rentals			2		2		2		3		2
Preferred dividends of subsidiaries (1)			10		6		6		1		2
Total fixed charges			561		609		628		640		681
Preferred dividends for purpose of ratio			-		-		-		-		-
Total fixed charges and preferred dividends for purpose of ratio		$	561	$	609	$	628	$	640	$	681
Earnings:
Pretax income from continuing operations before adjustment for income or loss from equity investees		$	1,747	$	1,255	$	1,399	$	1,443	$	1,600
Add:
Total fixed charges (from above)			561		609		628		640		681
Distributed income of equity investees			96		50		51		61		83
Less:
Interest capitalized			27		53		23		40		69
Preferred dividends of subsidiaries (1)			10		6		6		1		2
Total earnings for purpose of ratio		$	2,367	$	1,855	$	2,049	$	2,103	$	2,293
Ratio of earnings to combined fixed charges and preferred stock dividends			4.22		3.05		3.26		3.29		3.37

Ratio of earnings to fixed charges			4.22		3.05		3.26		3.29		3.37

(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.

SDG&E exhibit 12.2



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


			2011		2012		2013		2014		2015
Fixed Charges and Preferred Stock Dividends:
Interest		$	193	$	220	$	231	$	238	$	241
Interest portion of annual rentals			1		1		1		1		1
Total fixed charges			194		221		232		239		242
Preferred stock dividends (1)			7		7		5		-		-
Combined fixed charges and preferred stock dividends for purpose of ratio		$	201	$	228	$	237	$	239	$	242
Earnings:
Pretax income from continuing operations		$	692	$	705	$	626	$	797	$	890
Total fixed charges (from above)			194		221		232		239		242
Less: Interest capitalized			1		-		-		1		-
Total earnings for purpose of ratio		$	885	$	926	$	858	$	1,035	$	1,132
Ratio of earnings to combined fixed charges and preferred stock dividends			4.40		4.06		3.62		4.33		4.68

Ratio of earnings to fixed charges			4.56		4.19		3.70		4.33		4.68

(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.

SCG Exhibit 12.3


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


			2011		2012		2013		2014		2015
Fixed Charges:
Interest		$	77	$	77	$	76	$	77	$	96
Interest portion of annual rentals			1		1		1		2		1
Total fixed charges			78		78		77		79		97
Preferred stock dividends (1)			2		2		2		2		2
Combined fixed charges and preferred stock dividends for purpose of ratio		$	80	$	80	$	79	$	81	$	99
Earnings:
Pretax income from continuing operations		$	431	$	369	$	481	$	472	$	558
Add: Total fixed charges (from above)			78		78		77		79		97
Less: Interest capitalized			1		1		1		1		1
Total earnings for purpose of ratio		$	508	$	446	$	557	$	550	$	654
Ratio of earnings to combined fixed charges and preferred stock dividends			6.35		5.58		7.05		6.79		6.61

Ratio of earnings to fixed charges			6.51		5.72		7.23		6.96		6.74

(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.

Sempra Energy/SDG&E/SoCalGas 12/31/2015 Ex. 13

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
Business Strategy			9
Key Events and Issues in 2015			9
Results of Operations
Overall Results of Operations of Sempra Energy and Factors Affecting the Results			12
Segment Results			15
Changes in Revenues, Costs and Earnings			21
Book Value Per Share			39
Capital Resources and Liquidity
Overview			39
Cash Flows from Operating Activities			44
Cash Flows from Investing Activities			46
Cash Flows from Financing Activities			52
Credit Ratings			59
Factors Influencing Future Performance
California Utilities			60
Sempra International			66
Sempra U.S. Gas & Power			68
Other Sempra Energy Matters			73
Litigation			73
Market Risk			73
Critical Accounting Policies and Estimates, and Key Noncash Performance Indicators			77
Information Regarding Forward-Looking Statements			84
Common Stock Data			86
Performance Graph – Comparative Total Shareholder Returns			87
Five-Year Summaries			88
Controls and Procedures
Evaluation of Disclosure Controls and Procedures			91
Management’s Report on Internal Control over Financial Reporting			91
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure			92
Reports of Independent Registered Public Accounting Firm			93
Consolidated Financial Statements
Sempra Energy			99
San Diego Gas & Electric Company			106
Southern California Gas Company			113
Notes to Consolidated Financial Statements			119
Glossary			250

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 2013 through 2015

§	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, and also in conjunction with “Risk Factors” contained in our 2015 Annual Report on Form 10-K.

OUR BUSINESS

Sempra Energy is a Fortune 500 energy-services holding company whose operating units invest in, develop and operate energy infrastructure, and provide gas and electricity services to their customers in North and South America. Our operating units are our California Utilities, which are San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), 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.

In the first quarter of 2013, a Sempra Energy subsidiary, Infraestructura Energética Nova, S.A.B. de C.V. (IEnova), completed a private offering in the U.S. and outside of Mexico and concurrent public offering in Mexico of common stock. IEnova is a separate legal entity, formerly known as Sempra México, S.A. de C.V., comprised of Sempra Energy’s operations in Mexico. IEnova is included within our Sempra Mexico reportable segment, but is not the same in its entirety as the reportable segment. In addition to the IEnova operating companies, the Sempra Mexico segment includes, among other things, certain holding companies and risk management activity. Also, IEnova’s financial results are reported in Mexico under International Financial Reporting Standards (IFRS), as required by the Mexican Stock Exchange (La Bolsa Mexicana de Valores, S.A.B. de C.V., or BMV) where the shares are traded under the symbol IENOVA. We discuss the offerings and IEnova further in Note 1 of the Notes to Consolidated Financial Statements.

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

SEMPRA ENERGY OPERATING UNITS AND REPORTABLE SEGMENTS

We provide here descriptions of each of the segments in our California Utilities, Sempra International and Sempra U.S. Gas & Power businesses for operations relating to 2015, 2014 and 2013 earnings. We provide additional information regarding regulatory matters and development projects at the California Utilities in “Factors Influencing Future Performance” below and in Notes 13 and 14 of the Notes to Consolidated Financial Statements. We provide additional information regarding development projects at each of Sempra International and Sempra U.S. Gas & Power segments in “Factors Influencing Future Performance” below.

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 a population of 3.6 million (1.4 million meters) § Provides natural gas to a population of 3.3 million (0.9 million 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 21.6 million (5.9 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 delivers 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, which include Palomar Energy Center, Miramar Energy Center, Desert Star Energy Center and Cuyamaca Peak Energy Plant. SDG&E also delivers natural gas through 0.9 million meters in San Diego County and transports electricity and natural gas for others.

Sempra Energy indirectly owns all of the common stock of SDG&E. SDG&E had publicly held preferred stock that was redeemed in October 2013. We discuss the redemption in Note 11 of the Notes to Consolidated Financial Statements.

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 (PPA) with Otay Mesa VIE.

SDG&E has a 20-percent ownership interest in San Onofre Nuclear Generating Station (SONGS), a 2,150-megawatt (MW) nuclear generating facility near San Clemente, California, that is in the process of being decommissioned by Southern California Edison Company (Edison), the majority owner of SONGS. Due to operating issues, SONGS was taken offline in 2012, and in June 2013, Edison made the decision to permanently retire the facility. We discuss the decommissioning of SONGS in Note 13 of the Notes to Consolidated Financial Statements.

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 5.9 million meters, covering a population of 21.6 million.

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. The program allows customers to better manage their natural gas procurement and transportation needs. SoCalGas owns four natural gas storage facilities. The facilities have a combined working gas capacity of 137 billion cubic feet (Bcf) and have over 200 injection, withdrawal and observation wells. The Aliso Canyon storage facility represents 63 percent of SoCalGas’ owned natural gas storage capacity. We discuss recent matters concerning the Aliso Canyon facility further in “Key Events and Issues in 2015” and “Factors Influencing Future Performance” below and in Note 15 of the Notes to Consolidated Financial Statements.

Sempra Energy indirectly owns all of the common stock of SoCalGas. SoCalGas 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.

SEMPRA INTERNATIONAL
	MARKET	GEOGRAPHIC REGION
SEMPRA SOUTH AMERICAN UTILITIES Develops, owns and operates, or holds interests in electric transmission, distribution and generation infrastructure	§ Provides electricity to a population of approximately 2 million (approximately 672,000 meters) in Chile and approximately 4.9 million consumers (approximately 1,053,000 meters) 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 import 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 South American Utilities

Chilquinta Energía S.A. (Chilquinta Energía), a wholly owned subsidiary of Sempra South American Utilities, is an electric distribution utility serving a population of approximately 2 million through approximately 672,000 meters in the cities of Valparaiso and Viña del Mar in central Chile. In November 2015, Chilquinta Energía’s joint venture, Eletrans S.A., completed construction of a 220-kilovolt (kV) transmission line in Chile. The project will earn a return in U.S. dollars, indexed to the Consumer Price Index for 20 years and a regulated return thereafter.

Sempra South American Utilities owns 83.6 percent of Luz del Sur S.A.A. (Luz del Sur), an electric distribution utility that serves approximately 4.9 million consumers through approximately 1,053,000 meters in the southern zone of metropolitan Lima, Peru, and delivers approximately one-third of all power used in the country. The remaining shares of Luz del Sur are held by institutional investors and the general public. Luz del Sur also owns Santa Teresa, a 100-MW hydroelectric power plant in Peru that began commercial operations in September 2015 and supplies electricity for Luz del Sur’s customers. Luz del Sur sells excess electricity generated from the Santa Teresa plant into the spot market.

Sempra South American Utilities also owns interests in Tecnored S.A. (Tecnored) in Chile and Tecsur S.A. (Tecsur) in Peru, two energy-services companies that provide electric construction and infrastructure services to Chilquinta Energía and Luz del Sur, as well as third parties. Tecnored also sells electricity to non-regulated customers.

Sempra Mexico

Gas Business

Pipelines. Sempra Mexico, through its subsidiary IEnova, 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 Petróleos Mexicanos (or 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 5,624 million cubic feet (MMcf) per day in 2015.

IEnova and PEMEX are 50-50 partners in the joint venture Gasoductos de Chihuahua (GdC). GdC develops and operates energy infrastructure in Mexico through three natural gas pipelines, an ethane pipeline, and a liquid petroleum gas pipeline and associated storage terminal.

In December 2012, through its GdC joint venture, IEnova 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. The pipeline was completed in phases during 2015. PEMEX has fully contracted the capacity under a 21-year contract denominated in U.S. dollars.

In January 2013, PEMEX announced that the first phase of the Los Ramones pipeline project was assigned to and would be developed by the GdC joint venture. The project is a 72-mile natural gas pipeline with two compression stations, from the northern portion of the state of Tamaulipas bordering the United States to Los Ramones in the Mexican state of Nuevo León. The capacity is fully contracted under a 25-year transportation services agreement with PEMEX denominated in Mexican pesos, with a contract rate based on the U.S. dollar investment, adjusted annually for inflation and fluctuation of the exchange rate. The pipeline began operations at the end of 2014, and construction and testing of the two compression stations was completed in December 2015.

In July 2015, IEnova entered into an agreement to purchase PEMEX’s 50-percent interest in GdC, which upon closing would increase its interest from 50 percent to 100 percent. As we discuss in Note 3 of the Notes to Consolidated Financial Statements, the parties are in the process of restructuring the transaction in response to issues raised in the review of the transaction by Mexico’s antitrust commission. Any restructured transaction remains subject to satisfactory completion of the Mexican antitrust review and may require further approvals from other Mexican authorities.

LNG. Sempra Mexico’s Energía Costa Azul LNG terminal in Baja California, Mexico is capable of processing 1 Bcf of natural gas per day. The Energía Costa Azul facility generates revenue under capacity services agreements with Shell and Gazprom, expiring in 2028, that permit them, together, to use one-half of the terminal’s capacity.

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 MMcf 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.

Natural Gas Distribution. Sempra Mexico’s natural gas distribution utility, Ecogas México, S. de R.L. de C.V. (Ecogas), operates in three separate areas in Mexico, and had approximately 113,000 meters (serving more than 400,000 consumers) and sales volume of approximately 69 MMcf per day in 2015.

Power Business

Natural Gas-Fired Generation. Sempra Mexico’s Termoeléctrica de Mexicali, a 625-MW natural gas-fired power plant, is located in Mexicali, Baja California, Mexico. It has an Energy Management Agreement (EMA) 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. 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. In February 2016, management approved a plan to market and sell Termoeléctrica de Mexicali, as we discuss in “Factors Influencing Future Performance” below and Note 18 of the Notes to Consolidated Financial Statements.

Wind Power Generation. The Energía Sierra Juárez wind generation project in Baja California is designed to provide up to 1,200 MW of capacity if fully developed. SDG&E has a 20-year contract for up to 155 MW of renewable power supplied from the first phase of the project, which became operational in June 2015. In July 2014, Sempra Mexico completed the sale of a 50-percent interest in the first phase of the project to a wholly owned subsidiary of InterGen N.V. We discuss the equity sale further in Note 3 of the Notes to Consolidated Financial Statements.

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: § natural gas pipelines and storage facilities § natural gas distribution utilities § a terminal in the U.S. for the import and export of LNG and sale of natural gas § marketing operations	§ Natural gas § Liquefied natural gas § Wholesale electricity	§ U.S.A.

Sempra Renewables

The following table provides information about the Sempra Renewables wind and solar energy generation facilities that were operational as of December 31, 2015. The generating capacity of these facilities is fully contracted under long-term PPAs for the periods indicated in the table.

The majority of Sempra Renewables’ wind farm assets also earn production tax credits (PTC) based on the number of megawatt hours of electricity they generate. A PTC is a federal subsidy that pays wind producers a flat rate for generating clean energy and enables wind producers like Sempra Renewables to pass on the benefit to its customers. Because PTCs last for ten years after project completion, any wind turbine that is under construction before the end of 2019 will earn a full decade of PTCs at phased-out rates beginning with construction starting in 2017 through 2019. The 78-MW Black Oak Getty Wind project currently under construction at Sempra Renewables is not subject to PTC phase-out. For each of the years ended December 31, 2015, 2014 and 2013, PTCs represented a large portion of our wind farm earnings, often exceeding earnings from operations.

SEMPRA RENEWABLES OPERATING FACILITIES
Capacity in Megawatts at December 31, 2015
Name		Generating capacity	PPA term in years	First in service(1)	Location
Wholly owned facility:
Copper Mountain Solar 1		58	20	2008	Boulder City, Nevada

Jointly owned facilities(2):
Auwahi Wind		11	20	2012	Maui, Hawaii
Broken Bow 2 Wind		38	25	2014	Custer County, Nebraska
Cedar Creek 2 Wind		125	25	2011	New Raymer, Colorado
Flat Ridge 2 Wind		235	20 and 25	2012	Wichita, Kansas
Fowler Ridge 2 Wind		100	20	2009	Benton County, Indiana
Mehoopany Wind		71	20	2012	Wyoming County, Pennsylvania
	Total wind	580
California solar partnership		55	25	2013	Tulare and Kings Counties, California
Copper Mountain Solar 2		75	25	2012	Boulder City, Nevada
Copper Mountain Solar 3		125	20	2014	Boulder City, Nevada
Mesquite Solar 1		75	20	2011	Arlington, Arizona
Total solar		330

Total MW in operation		968

(1) (2)		If placed in service in phases, indicates the year the first phase went into service. Sempra Renewables has a 50-percent interest in each of these facilities and accounts for them as equity method investments. The generating capacity represents Sempra Renewables’ share only.

Copper Mountain Solar 2 is divided into two phases totaling 150 MW. The 92-MW first phase was placed in service in November 2012 and the 58-MW second phase was placed in service in April 2015. The 150-MW Mesquite Solar 1 facility went fully into service in December 2012. In the third quarter of 2013, Sempra Renewables sold 50-percent equity interests in the Copper Mountain Solar 2 and Mesquite Solar 1 facilities to Consolidated Edison Development (Con Edison Development).

Copper Mountain Solar 3 achieved full commercial operation in April 2015 and totals 250 MW, including 184 MW placed in service in 2014. In March 2014, Sempra Renewables completed the sale of a 50-percent equity interest in Copper Mountain Solar 3 to Con Edison Development.

In May 2014, Sempra Renewables acquired a 50-percent ownership interest in four, fully operating solar facilities in California, or the California solar partnership.

In October 2014, the 75-MW Broken Bow 2 Wind project achieved commercial operation and, in November 2014, Sempra Renewables sold a 50-percent equity interest in Broken Bow 2 Wind to Con Edison Development.

We discuss the equity sales and purchase of these facilities and related matters further in Notes 3 and 4 of the Notes to Consolidated Financial Statements. We discuss capacity under development in “Factors Influencing Future Performance” below.

Sempra Natural Gas

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 services 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 the Rocky Mountain region to the upper Midwest and the eastern United States. Our ownership interest in the pipeline is 25 percent. Sempra Natural Gas has an agreement through November 2019 with Rockies Express for 0.2 Bcf per day of capacity on REX, which has a total west-to-east capacity of 1.8 Bcf per day. Sempra Natural Gas has entered and continues to enter into new capacity release arrangements with other third parties, but these agreements have not been sufficient to offset all of our capacity payments to Rockies Express.

In April 2014, prior to the launching of an open season, Rockies Express had secured binding financial commitments with four shippers totaling 1.2 Bcf per day of capacity for east-to-west transportation services for a term of 20 years originating at or near Clarington, Ohio. Rockies Express placed this capacity into service on August 1, 2015. In June 2014, Rockies Express finished constructing the Seneca Lateral, an initial 0.25 Bcf per day capacity project that connects natural gas production sources in Ohio to REX. The lateral’s capability was further expanded to 0.6 Bcf per day of capacity in January 2015. The lateral is fully contracted through September 2021.

We discuss our investment in Rockies Express in Note 4 of the Notes to Consolidated Financial Statements.

Distribution. Our Sempra Natural Gas segment 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 delivers natural gas through approximately 85,000 meters (serving more than 200,000 consumers), and Willmut Gas delivers natural gas through approximately 19,000 meters (serving over 50,000 consumers).

LNG. The Cameron LNG, LLC regasification terminal in Hackberry, Louisiana, 100-percent owned by Sempra Natural Gas until October 1, 2014, is capable of processing 1.5 Bcf of natural gas per day. The terminal generates revenue under a terminal services agreement for approximately 3.75 Bcf of natural gas storage and associated send-out rights of approximately 600 MMcf of natural gas per day through 2029, subject to the termination agreement discussed below. The agreement allows the customer to pay capacity reservation and usage fees to use the facilities to receive, store and regasify the customer’s LNG. Sempra Natural Gas also may enter into short-term supply agreements to purchase LNG to be received, stored and regasified at the terminal for sale to other parties.

In August 2014, Sempra Energy and three project partners provided their respective final investment decision with regard to the Cameron LNG Holdings, LLC (Cameron LNG JV) joint venture for the development, construction and operation of a natural gas liquefaction export facility at the Cameron LNG terminal. Beginning from the October 1, 2014 joint venture effective date, Cameron LNG, LLC is no longer wholly owned, and Sempra Natural Gas accounts for its investment in the joint venture under the equity method.

The liquefaction facility, on which construction began in the second half of 2014, will utilize Cameron LNG’s existing facilities, including two marine berths, three LNG storage tanks, and vaporization capability of 1.5 Bcf per day. The joint venture has authorization to export LNG to both Free Trade Agreement (FTA) countries and to countries that do not have an FTA with the United States. Cameron LNG JV has 20-year liquefaction and regasification tolling capacity agreements in place with ENGIE S.A. (formerly GDF SUEZ S.A.) and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd., that subscribe the full nameplate capacity of the facility. We discuss activities related to the Cameron LNG export project further in “Factors Influencing Future Performance” below and in Notes 3 and 4 of the Notes to Consolidated Financial Statements.

There is a termination agreement in place related to the terminal services agreement discussed above that will result in the termination of the agreement at the point during construction of the new liquefaction facilities where piping tie-ins to the existing regasification terminal become necessary. Based on the full notice to proceed that was issued to Cameron LNG JV’s engineering, procurement and construction (EPC) contractor in October 2014, we expect this termination date to occur during the first half of 2017.

Sempra Natural Gas has an LNG purchase agreement with Tangguh PSC for the supply of the equivalent of 500 MMcf 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. 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.

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 Sempra Mexico’s Termoeléctrica de Mexicali power plant, described above, and prior to April 2015, to fuel its Mesquite Power natural gas-fired power plant. Sempra Natural Gas sold the first 625-MW block of the Mesquite Power plant in February 2013 and the remaining 625-MW block, together with a related power sales contract, in April 2015.

Related to its Mesquite Power plant, Sempra Natural Gas had power sale transactions with various counterparties intended to hedge its generation capacity. Sempra Natural Gas sold certain quantities of expected future generation output under long-term contracts. The remaining output of the Mesquite Power plant prior to the sale in April 2015 was available to be sold into energy markets on a day-ahead basis, as is the output of Sempra Mexico’s Termoeléctrica de Mexicali power plant.

Sempra Natural Gas has an EMA with Sempra Mexico to provide energy marketing, scheduling and other related services to Sempra Mexico’s Termoeléctrica de Mexicali power plant to support its sales of generated power into the California electricity market. We discuss the EMA in “Sempra Mexico – Power Business – Natural Gas-Fired Generation” above.

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 California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR) regulates the operations of SoCalGas’ natural gas storage facilities.

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

Our South American utilities are regulated by federal and local governmental agencies. The National Energy Commission (Comisión Nacional de Energía, 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 objective is to increase shareholder value by developing and operating long-term-contracted energy infrastructure assets and regulated utilities in a safe and reliable manner.

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

§	U.S. utilities

§	South American utilities and Mexican midstream, including LNG

§	U.S. natural gas midstream, including LNG, and renewables

Operating within these areas, we are focused on generating stable, predictable earnings and cash flows by investing in assets that are primarily regulated or contracted long-term. We have a robust capital program over the next several years and will take a disciplined approach to deploying this capital to areas that fit our strategy and are designed to create shareholder value. By doing so, our goal is to deliver long-term growth that is in excess of what you find in the utility space but with a risk profile in line with our utility peers.

KEY EVENTS AND ISSUES IN 2015

Below are key events and issues, including major project updates, that affected our business in 2015; some of these may continue to affect our future results. Each event/issue includes the page number you may reference for additional details.

Key Events and Issues:

§	California Utilities:

□

In October 2015, SoCalGas discovered a leak at one of its natural gas injection and withdrawal wells at its Aliso Canyon natural gas storage facility located in the northern part of the San Fernando Valley in Los Angeles County, resulting in numerous complaints filed against SoCalGas and Sempra Energy, governmental investigations, and an order being issued by the Governor of California proclaiming a state of emergency to exist in Los Angeles County. On February 18, 2016, DOGGR confirmed that the leaking well had been permanently sealed and taken out of service (page 228).

□

In September 2015, the California Utilities filed settlement agreements with the CPUC that resolve all material matters related to their 2016 General Rate Case (2016 GRC) proceeding, except for the revenue requirement implications of certain income tax benefits associated with flow-through repair allowance deductions (page 216).

□

In September 2015, the California Utilities filed an application with the CPUC seeking authority to recover the full cost of the Pipeline Safety & Reliability Project, which involves construction of an approximately 47-mile, 36-inch natural gas transmission pipeline with an estimated cost of $600 million (page 224).

□	In September 2015, SDG&E filed an application with the CPUC requesting to recover an estimated $379 million in costs related to the October 2007 wildfires in rates over a six- to ten-year period (page 222).

□	In July 2015, the CPUC adopted a revised Administrative Law Judge (ALJ)-proposed decision that establishes comprehensive reform for residential electric rate design. In addition, the CPUC adopted a successor net energy metering, or NEM, tariff in January 2016 (page 63).

□

In October 2015, the SONGS co-owners (Edison, SDG&E and the City of Riverside) reached an agreement with Nuclear Electric Insurance Limited (NEIL) to resolve all of SONGS’ insurance claims arising out of the failures of the replacement steam generators. SDG&E’s share is approximately $80 million, of which $75 million was allocated to ratepayers (page 214).

□	In November 2015, the CPUC approved a one-year extension until April 2017 for SDG&E and SoCalGas to file their next Cost of Capital application, maintaining both companies’ current authorized rates of return and capital structure through December 2017 (page 217).

§	Sempra Mexico:

□

In July 2015, Sempra Mexico’s subsidiary, IEnova, entered into an agreement to purchase PEMEX’s 50-percent interest in GdC, which upon closing would increase its interest from 50 percent to 100 percent. As we discuss in Note 3 of the Notes to Consolidated Financial Statements, the parties are in the process of restructuring the transaction in response to issues raised in the review of the transaction by Mexico’s antitrust commission. Any restructured transaction remains subject to satisfactory completion of the Mexican antitrust review and may require further approvals from other Mexican authorities (page 150).

§	Sempra Natural Gas:

□

In February 2015, Rockies Express received FERC approval for a project that had previously secured binding financial commitments with four shippers totaling 1.2 Bcf per day of capacity for east-to-west transportation services for a term of 20 years originating at or near Clarington, Ohio. This capacity went into service in August 2015 (page 7).

□	In March 2015, Rockies Express requested FERC approval of the Zone 3 Capacity Enhancement Project, an expansion of REX’s east-to-west capability of 0.8 Bcf per day that has an estimated cost of $530 million (page 70).

□	In April 2015, Sempra Natural Gas sold the remaining 625-MW block of the Mesquite Power plant, together with a related power sales contract, for net cash proceeds of $347 million (page 151).

Major Project Updates:

§	Sempra Natural Gas’ Cameron liquefaction projects:

□

In February 2015, Cameron LNG JV filed the U.S. Department of Energy (DOE) FTA application and the pre-filing application at FERC for two additional liquefaction trains and one additional full containment LNG storage tank at the Cameron LNG liquefaction facility, and in May 2015, filed the corresponding DOE Non-FTA permit application. The DOE FTA approval was received in July 2015 and the FERC application was submitted in September 2015 and formally noticed in October 2015. The Cameron LNG liquefaction project, comprised of Cameron LNG JV’s existing facilities and three liquefaction trains, is currently under construction and is expected to achieve commercial operation of all three trains in 2018, and have the first year of full operations in 2019 (page 71).

□	In April 2015, Cameron LNG JV filed with the DOE for authorization to match the total export volumes allowed to be exported to Non-FTA countries with the volumes under the FERC permit for FTA countries for the current three-train liquefaction construction project (page 71).

§	Sempra Energy’s other LNG liquefaction development projects:

□	In February 2015, Sempra Natural Gas, IEnova, and a subsidiary of PEMEX entered into a Memorandum of Understanding (MOU) to collaborate in the development of a potential natural gas liquefaction project at IEnova’s existing regasification terminal at Energía Costa Azul (page 68).

□	In March 2015, Sempra Natural Gas submitted requests to the FERC to initiate the pre-filing review for the proposed Port Arthur LNG natural gas liquefaction and export facility in Port Arthur, Texas, and the proposed Port Arthur pipeline project (page 72).

□	In March and June 2015, Sempra Natural Gas filed permit applications with the DOE for authorization to export the LNG produced from the proposed Port Arthur LNG facility to all current and future FTA and Non-FTA countries, respectively. The DOE FTA approval was received in August 2015 (page 72).

□

§	Sempra Mexico:

□	In June 2015, the 155-MW first phase of Sempra Mexico’s Energía Sierra Juárez wind generation project began commercial operations (page 68).

□

In July 2015, Sempra Mexico entered into the San Isidro - Samalayuca pipeline (San Isidro pipeline) natural gas transportation services agreement with the CFE for a 25-year term, denominated in U.S. dollars. Sempra Mexico will be responsible for the development, construction and operation of the approximately 14-mile pipeline, with an estimated cost of $110 million (page 68).

□	In August 2015, Sempra Mexico completed construction of the final section of the first segment of the Sonora pipeline, a 500-mile natural gas pipeline network in northern Mexico (page 67).

□	In December 2015, Sempra Mexico, through its joint venture with PEMEX, completed construction of the 140-mile pipeline to transport ethane from Tabasco, Mexico to Veracruz, Mexico (page 5).

□

In December 2015, Sempra Mexico, through its joint venture with PEMEX, completed construction and testing of the two compression stations related to the 72-mile Los Ramones I pipeline to transport natural gas from Frontera, Tamaulipas to Ramones, Nuevo León, in Mexico. The pipeline started operations in December 2014 (page 5).

§	Sempra South American Utilities:

□	In September 2015, Luz del Sur began commercial operation of Santa Teresa, a 100-MW hydroelectric power plant in Peru’s Cusco region (page 5).

□	In November 2015, Chilquinta Energía’s joint venture, Eletrans S.A., completed construction of a 220-kV transmission line in Chile (page 67).

§	Sempra Renewables:

□	In March 2015, Sempra Renewables acquired a 100-percent interest in the Black Oak Getty Wind project, a 78-MW wind farm under development in Stearns County, Minnesota (page 150).

□	In March 2015, the CPUC approved Sempra Renewables’ 20-year power sale agreement with Edison for all of the solar power from the 94-MW Copper Mountain Solar 4 facility beginning in 2020 (page 69).

□	In April 2015, the 58-MW second phase of Sempra Renewables’ Copper Mountain Solar 2 facility was placed in service (page 7).

□	In April 2015, Sempra Renewables’ 250-MW Copper Mountain Solar 3 facility achieved full commercial operation (page 69).

□	In June 2015, Sempra Renewables signed a 20-year power sale agreement with Edison, approved by the CPUC in December 2015, for 100 MW of solar power from the second phase of Mesquite Solar (Mesquite Solar 2) (page 69).

□	In July 2015, Sempra Renewables signed a 25-year power sale agreement with the Western Area Power Administration on behalf of the U.S. Department of the Navy for 150 MW of solar power from the third phase of Mesquite Solar (Mesquite Solar 3) (page 69).

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 results of operations information for our overall operations from 2011 to 2015.

OVERALL OPERATIONS OF SEMPRA ENERGY FROM 2011 TO 2015

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

[a008.gif]

[a004.gif]

In 2015, our earnings increased by $188 million (16%) to $1.3 billion and our diluted earnings per share increased by $0.74 per share (16%) to $5.37 per share. The net increases in our earnings and diluted earnings per share were primarily impacted by the following increases (decreases), by segment:

SDG&E

§	$40 million higher earnings from CPUC base operations and from electric transmission

$15 million reduction to the loss from plant closure in 2015 primarily based on CPUC approval of a compliance filing related to SDG&E’s authorized recovery of its investment in SONGS compared to a $21 million increase to the loss in 2014, as we discuss in Note 13 of the Notes to Consolidated Financial Statements

SoCalGas

§	$34 million higher earnings primarily due to a lower effective tax rate, including $11 million earnings impact from higher favorable resolution of prior years’ income tax items in 2015

§	$31 million higher earnings from CPUC base operating margin authorized for 2015

$11 million of earnings from a retroactive increase, approved by the CPUC in 2015, in authorized General Rate Case (GRC) revenue requirement for years 2012 through 2014 due to increased rate base, as we discuss in “SoCalGas Matters – Increase to CPUC-Authorized Annual Revenue Requirement” in Note 14 of the Notes to Consolidated Financial Statements

Sempra South American Utilities

§	$21 million higher earnings from operations, mainly in Peru, due to an increase in volumes and rates, which rates include foreign currency adjustments

§	$7 million business interruption proceeds for the Santa Teresa hydroelectric power plant, which was expected to begin commercial operation in September 2014, but did not commence operation until September 2015 due to construction delays

§	$(20) million lower earnings from foreign currency effects

Sempra Mexico

§	$37 million higher pipeline earnings, primarily due to the start of operations of certain pipelines in the fourth quarter of 2014

§	$31 million favorable variance due to effects from foreign currency and inflation, including amounts in earnings from our joint ventures

§	$(5) million losses in 2015 from operations at our Mexicali power plant compared to $(13) million earnings for the same period in 2014, primarily due to lower capacity revenues and lower volumes

§	$(14) million gain in 2014 from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez project

Sempra Renewables

§	$(24) million gains in 2014 from the sale of 50-percent equity interests in Copper Mountain Solar 3 and Broken Bow 2 Wind

Sempra Natural Gas

§	$36 million gain on the April 2015 sale of the remaining 625-MW block of the 1,250-MW Mesquite Power natural gas-fired power plant, and a related power sale contract

§	$11 million higher equity earnings at Rockies Express due to additional capacity placed in service in 2015

§	$(29) million lower results from LNG marketing operations, primarily driven by the effect of lower natural gas prices

§	$(25) million tax benefit in 2014 due to the release of Louisiana state valuation allowance against a deferred tax asset associated with Cameron LNG developments

Parent and Other

§	$39 million higher income tax benefits, including $18 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries, as we discuss below under “Changes in Revenues, Costs and Earnings – Income Taxes”

§	$(11) million lower investment gains in 2015 on dedicated assets in support of our executive retirement and deferred compensation plans, net of the decrease in deferred compensation liability associated with the investments

In 2014 compared to 2013, our earnings increased by $160 million (16%) to $1.2 billion and our diluted earnings per share increased by $0.62 per share (15%) to $4.63 per share. The net increases in our earnings and diluted earnings per share were primarily impacted by the following increases (decreases), by segment:

SDG&E

§	$119 million charge in 2013 for loss from plant closure associated with SDG&E’s investment in SONGS, compared to a $(21) million charge in 2014 to adjust the total loss from plant closure, as we discuss in Note 13 of the Notes to Consolidated Financial Statements

§	$24 million higher CPUC base operating margin authorized for 2014 and lower non-refundable operating costs

§	$15 million favorable resolution of prior years’ income tax items in 2014 compared to a $2 million unfavorable resolution in 2013

§	$(52) million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC, which was approved by the CPUC in May 2013 and effective retroactive to January 1, 2012

SoCalGas

§	$24 million higher CPUC base operating margin authorized for 2014, net of higher non-refundable operating costs

$(30) million higher income tax expense primarily due to lower favorable resolution of prior years’ income tax items in 2014, higher reversal through book depreciation of previously recognized tax benefits for a certain portion of utility fixed assets and lower deductions for self-developed software expenditures

§	$(25) million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC

Sempra South American Utilities

§	$18 million income tax benefit related to Peruvian tax reform, offset by $(6) million income tax expense related to Chilean tax reform

Sempra Mexico

§	$30 million favorable impact due to the effects on tax-related balances from foreign currency and inflation

§	$24 million higher AFUDC in 2014 related to equity associated with construction of the natural gas pipeline in Sonora

§	$14 million gain from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez project in 2014

§	$13 million income tax expense in 2013 due to Mexican tax reform

§	$(21) million impact of higher earnings attributable to noncontrolling interests at IEnova ($47 million in 2014 compared to $26 million in 2013)

Sempra Renewables

§	$24 million gains in 2014 from the sale of 50-percent equity interests in Copper Mountain Solar 3 and Broken Bow 2 Wind

§	$19 million higher deferred income tax benefits, including the benefits from projects placed in service in 2014 and a $5 million reduction of benefits in 2013 as a result of U.S. Treasury grant sequestration

§	$(24) million gains in 2013 from the sale of 50-percent equity interests in Mesquite Solar 1 and Copper Mountain Solar 2

Sempra Natural Gas

§	$25 million tax benefit due to the release in 2014 of a Louisiana state valuation allowance against a deferred tax asset associated with Cameron LNG developments

§	$(44) million gain in 2013 on the sale of the first 625-MW block of the Mesquite Power plant

Parent and Other

§	$63 million income tax expense in 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings

§	$(38) million income tax expense in 2014 for repatriation of current year foreign earnings

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

SEMPRA ENERGY EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)
	Years ended December 31,
	2015						2014						2013
California Utilities:
SDG&E(1)		$	587		43	%		$	507		44	%		$	404		41		%
SoCalGas(2)			419		31				332		29				364		37
Sempra International:
Sempra South American Utilities			175		13				172		15				153		15
Sempra Mexico			213		16				192		16				122		12
Sempra U.S. Gas & Power:
Sempra Renewables			63		5				81		7				62		6
Sempra Natural Gas			44		3				50		4				64		6
Parent and other(3)			(152	)	(11	)			(173	)	(15	)			(168	)	(17	)
Earnings		$	1,349		100	%		$	1,161		100	%		$	1,001		100		%

(1)

For 2013, amount is after preferred dividends and call premium on preferred stock.

(2)

After preferred dividends.

(3)

Includes after-tax interest expense ($157 million in 2015 and $144 million in each of 2014 and 2013), intercompany eliminations recorded in consolidation and certain corporate costs.

SEGMENT RESULTS

The following section is a discussion of earnings (losses) by Sempra Energy segment, as well as Parent and other, as presented in the table above. Variance amounts are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise noted.

EARNINGS BY SEGMENT – CALIFORNIA UTILITIES

(Dollars in millions)

[a010.gif]

SDG&E

Our SDG&E segment recorded earnings of:

§	$587 million in 2015

§	$507 million in 2014

§	$404 million in 2013 ($411 million before preferred dividends and call premium)

The increase in earnings of $80 million (16%) in 2015 was primarily due to:

§	$15 million reduction to the loss from plant closure in 2015 primarily based on the CPUC approval of a compliance filing related to SDG&E’s authorized recovery of its investment in SONGS compared to a $21 million charge in 2014 to adjust the total loss from plant closure;

§	$26 million higher earnings from electric transmission operations primarily due to higher rate base;

§	$14 million higher CPUC base operating margin authorized for 2015, and lower non-refundable operating costs;

§	$7 million lower generation major maintenance costs; and

§	$7 million higher favorable resolution of prior years’ income tax items; offset by

§	$7 million higher earnings in 2014 associated with SDG&E’s annual FERC formulaic rate adjustment.

The increase of $103 million (25%) in 2014 compared to 2013 was primarily due to:

§	$119 million charge in 2013 for loss from plant closure associated with SDG&E’s investment in SONGS, compared to a $21 million charge in 2014 to adjust the total loss from plant closure;

§	$24 million higher CPUC base operating margin authorized for 2014 and lower non-refundable operating costs;

§	$15 million favorable resolution of prior years’ income tax items in 2014 compared to a $2 million unfavorable resolution in 2013; and

§	$3 million lower litigation expense in 2014; offset by

§	$52 million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC; and

§	$7 million lower earnings from electric transmission operations primarily due to lower FERC-authorized return on equity.

SoCalGas

Our SoCalGas segment recorded earnings of:

§	$419 million in 2015 ($420 million before preferred dividends)

§	$332 million in 2014 ($333 million before preferred dividends)

§	$364 million in 2013 ($365 million before preferred dividends)

The increase in earnings of $87 million (26%) in 2015 was primarily due to:

§	$34 million higher earnings primarily due to a lower effective tax rate, including $11 million earnings impact from higher favorable resolution of prior years’ income tax items in 2015;

§	$31 million higher CPUC base operating margin authorized for 2015, and lower non-refundable operating costs;

§	$11 million of earnings from a retroactive increase, approved by the CPUC in 2015, in authorized GRC revenue requirement for years 2012 through 2014 due to increased rate base;

§	$10 million from an increase in AFUDC related to equity; and

§	$8 million higher regulatory awards; offset by

§	$8 million higher interest expense.

The decrease in earnings of $32 million (9%) in 2014 compared to 2013 was primarily due to:

§	$25 million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC;

§	$15 million lower favorable resolution of prior years’ income tax items in 2014;

§	$15 million increase in income tax expense primarily due to higher reversal through book depreciation of previously recognized tax benefits for a certain portion of utility fixed assets, and from lower deductions for self-developed software expenditures;

§	$5 million write-off in 2014 of certain costs incurred associated with the Pipeline Safety Enhancement Plan (PSEP) that were disallowed for recovery in the final PSEP decision; and

§	$4 million insurance recovery in 2013 of previously expensed costs; offset by

§	$24 million higher CPUC base operating margin authorized for 2014, net of higher non-refundable operating costs; and

§	$9 million from an increase in AFUDC related to equity.

EARNINGS BY SEGMENT – SEMPRA INTERNATIONAL

(Dollars in millions)

[a011.gif]

Sempra South American Utilities

Our Sempra South American Utilities segment recorded earnings of:

§	$175 million in 2015

§	$172 million in 2014

§	$153 million in 2013

Because our operations in South America use their local currency as their functional currency, revenues and expenses are translated into U.S. dollars at average exchange rates for the year for consolidation in Sempra Energy Consolidated’s results of operations. The year-to-year variances discussed below are as adjusted for the difference in foreign currency translation rates between years.

The increase in earnings of $3 million (2%) in 2015 was primarily due to:

§	$21 million higher earnings from operations, mainly in Peru, due to an increase in volumes and rates, which rates include foreign currency adjustments;

§	$7 million business interruption proceeds for the Santa Teresa hydroelectric power plant, which was expected to begin commercial operation in September 2014, but did not commence operation until September 2015 due to construction delays;

§	$4 million higher earnings from early termination fees from commercial power contracts;

§	$4 million decrease in earnings attributable to noncontrolling interests in 2015; and

§	$3 million lower net interest expense, mainly in Chile, related to inflationary effect on local bonds; offset by

§	$20 million lower earnings from foreign currency effects;

$9 million higher income tax expense, including $18 million income tax benefit in 2014 related to Peruvian tax reform, offset by $6 million income tax expense in 2014 related to Chilean tax reform, as we discuss below in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes;” and

§	$8 million lower earnings associated with the relocation of electrical infrastructure.

The increase in earnings of $19 million (12%) in 2014 compared to 2013 was primarily due to:

§	$18 million income tax benefit related to Peruvian tax reform, offset by $6 million income tax expense related to Chilean tax reform;

§	$12 million higher earnings associated with the relocation of electrical infrastructure;

§	$11 million equity losses in 2013 related to the sale of our investments in two Argentine natural gas utility holding companies; and

§	$10 million higher earnings from operations mainly due to an increase in volume, primarily from customer growth; offset by

§	$16 million lower earnings from foreign currency effects;

§	$5 million increase in earnings attributable to noncontrolling interests in 2014; and

§	$5 million higher interest expense mainly in Chile related to the inflationary effect on local bonds.

Sempra Mexico

Sempra Mexico recorded earnings of:

§	$213 million in 2015

§	$192 million in 2014

§	$122 million in 2013

The increase in earnings of $21 million (11%) in 2015 was primarily due to:

§	$37 million higher pipeline earnings, primarily due to the start of operations of certain pipelines in the fourth quarter of 2014; and

§	$31 million favorable variance due to effects from foreign currency and inflation, including amounts in earnings from our joint ventures; offset by

§	$5 million losses in 2015 from operations at our Mexicali power plant compared to $13 million earnings for the same period in 2014, primarily due to lower capacity revenues and lower volumes;

§	$14 million gain in 2014 from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez project;

§	$10 million unfavorable impact from income taxes ($5 million expense in 2015 compared to $5 million benefit in 2014); and

§	$6 million increase in earnings attributable to noncontrolling interests at IEnova.

The increase in earnings of $70 million (57%) in 2014 compared to 2013 was primarily due to:

§	$30 million favorable impact ($29 million benefit in 2014 and $1 million expense in 2013) primarily due to the effects on tax-related balances from foreign currency and inflation;

§	$24 million higher earnings from operations mainly due to prior year’s scheduled major maintenance and improved results at our Mexicali power plant, and start of operations of a section of the Sonora pipeline;

§	$24 million higher AFUDC in 2014 related to equity associated with construction of the natural gas pipeline in Sonora;

§	$14 million gain from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez wind project in 2014; and

§	$13 million income tax expense in 2013 due to Mexican tax reform; offset by

§	$21 million higher earnings attributable to noncontrolling interests at IEnova in 2014; and

§	$15 million unfavorable translation effect primarily on Peso-denominated receivables.

EARNINGS BY SEGMENT – SEMPRA U.S. GAS & POWER

(Dollars in millions)

[a012.gif]

Sempra Renewables

Sempra Renewables recorded earnings of:

§	$63 million in 2015

§	$81 million in 2014

§	$62 million in 2013

The decrease in earnings of $18 million (22%) in 2015 was primarily due to:

§	$24 million gains in 2014 from the sale of 50-percent equity interests in Copper Mountain Solar 3 and Broken Bow 2 Wind; offset by

§	$5 million gain in 2015 from the sale of the Rosamond Solar development project, as we discuss in Note 3 of the Notes to Consolidated Financial Statements; and

§	$4 million higher earnings from increased solar capacity, offset by lower earnings from decreased production at wind projects.

The increase in earnings of $19 million (31%) in 2014 compared to 2013 was primarily due to:

§	$24 million gains in 2014 from the sale of 50-percent equity interests in Copper Mountain Solar 3 and Broken Bow 2 Wind; and

§	$19 million higher deferred income tax benefits, including the benefits of projects placed in service in 2014 and a $5 million reduction of benefits in 2013 as a result of U.S. Treasury grant sequestration; offset by

§	$24 million gains in 2013 from the sale of 50-percent equity interests in Mesquite Solar 1 and Copper Mountain Solar 2.

Sempra Natural Gas

Sempra Natural Gas recorded earnings of:

§	$44 million in 2015

§	$50 million in 2014

§	$64 million in 2013

The decrease in earnings of $6 million (12%) in 2015 was primarily due to:

§	$29 million lower results from LNG marketing operations, primarily driven by the effect of lower natural gas prices;

§	$25 million tax benefit in 2014 due to the release of Louisiana state valuation allowance against a deferred tax asset associated with Cameron LNG developments; and

§	$10 million development expense associated with the potential expansion of our LNG business; offset by

§	$36 million gain in 2015 on the sale of the remaining 625-MW block of the Mesquite Power plant and a related power sale contract, net of related expenses;

§	$11 million higher equity earnings from Rockies Express due to additional capacity placed in service in 2015; and

§	$9 million lower net losses from the Mesquite Power plant due to the sale of the remaining block in April 2015.

The decrease in earnings of $14 million (22%) in 2014 compared to 2013 was primarily due to:

§	$44 million gain in 2013 on the sale of the first 625-MW block of its Mesquite Power plant, net of related expenses; and

§	$15 million lower results from gas storage operations and natural gas marketing activities; offset by

§	$25 million tax benefit due to the release in 2014 of a Louisiana state valuation allowance against a deferred tax asset associated with Cameron LNG developments;

§	$10 million lower operating costs at the Mesquite Power plant, primarily depreciation due to the classification of the remaining 625-MW block as an asset held for sale; and

§	$9 million higher net intercompany interest income.

Parent and Other

Losses for Parent and Other were

§	$152 million in 2015

§	$173 million in 2014

§	$168 million in 2013

The decrease in losses of $21 million (12%) in 2015 was primarily due to:

§	$39 million higher income tax benefits, including

□	$18 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries,

□	$14 million of income tax benefits in 2015 associated with the resolution of prior years’ income tax items, and

□	$5 million higher income tax benefits from a decrease in state valuation allowances; offset by

§	$11 million lower investment gains in 2015 on dedicated assets in support of our executive retirement and deferred compensation plans, net of the decrease in deferred compensation liability associated with the investments.

The increase in losses of $5 million (3%) in 2014 compared to 2013 was primarily due to:

§	$38 million income tax expense in 2014 from the repatriation of current year foreign earnings;

§	$9 million lower investment gains on dedicated assets in support of our executive retirement and deferred compensation plans, net of the decrease in deferred compensation liability associated with the investments;

§	$9 million higher net interest expense; and

§	$8 million lower income tax benefits in 2014, excluding income tax items discussed separately; offset by

§	$63 million income tax expense in 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings.

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 subsequent periods through rates.

The table below summarizes revenues and cost of sales for our utilities, net of intercompany activity:

UTILITIES REVENUES AND COST OF SALES
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Electric revenues:
SDG&E	$	3,719		$	3,785		$	3,537
Sempra South American Utilities		1,447			1,434			1,383
Eliminations and adjustments		(8	)		(10	)		(9	)
Total		5,158			5,209			4,911
Natural gas revenues:
SoCalGas		3,489			3,855			3,736
SDG&E		500			544			529
Sempra Mexico		81			109			97
Sempra Natural Gas		103			113			109
Eliminations and adjustments		(77	)		(72	)		(73	)
Total		4,096			4,549			4,398
Total utilities revenues	$	9,254		$	9,758		$	9,309
Cost of electric fuel and purchased power:
SDG&E	$	1,151		$	1,309		$	1,019
Sempra South American Utilities		985			972			913
Total	$	2,136		$	2,281		$	1,932
Cost of natural gas:
SoCalGas	$	921		$	1,449		$	1,362
SDG&E		153			208			204
Sempra Mexico		49			74			63
Sempra Natural Gas		31			44			35
Eliminations and adjustments		(20	)		(17	)		(18	)
Total	$	1,134		$	1,758		$	1,646

Sempra Energy Consolidated

Electric Revenues

Our electric revenues decreased by $51 million (1%), remaining at $5.2 billion in 2015 primarily due to:

§	$66 million decrease at SDG&E, including:

□	$158 million lower cost of electric fuel and purchased power, which we discuss below, and

□	$57 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses, offset by

□

$88 million higher revenues from CPUC-authorized 2015 attrition and, starting in 2015, authorized revenues for the recovery of the SONGS regulatory assets pursuant to an amended settlement agreement approved by the CPUC in 2014, which we discuss below in “Depreciation and Amortization” and in Note 13 of the Notes to Consolidated Financial Statements, and

□	$52 million higher authorized revenues from electric transmission; offset by

§	$13 million increase at Sempra South American Utilities, including:

□	higher rates and volumes at Luz del Sur, offset by foreign currency effects, and

□	$9 million business interruption proceeds in 2015, offset by

□	foreign currency effects at Chilquinta Energía, offset by higher rates and volumes, and

□

lower revenues and volumes associated with the transfer of certain non-regulated customers from Chilquinta Energía to Tecnored, an energy-services subsidiary of Sempra South American Utilities. Our energy-service companies are part of our energy-related businesses, which revenues are discussed below in “Energy-Related Businesses: Revenues and Cost of Sales.”

In 2014 compared to 2013, our electric revenues increased by $298 million (6%) to $5.2 billion primarily due to:

§	$248 million increase at SDG&E, including:

□	$290 million increase in cost of electric fuel and purchased power, which we discuss below,

□	$39 million increase in authorized revenues from 2014 attrition, and

□	$32 million higher authorized revenues from electric transmission, offset by

□	$61 million favorable impact on 2013 revenues from the retroactive application of the 2012 GRC decision for the period from January 2012 through December 2012, and

□	$47 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; and

§	$51 million increase at Sempra South American Utilities primarily due to higher rates and volumes at both Luz del Sur and Chilquinta Energía, offset by foreign currency exchange rate effects.

Our utilities’ cost of electric fuel and purchased power decreased by $145 million (6%) to $2.1 billion in 2015 primarily due to:

§	$158 million decrease at SDG&E, which we discuss below; offset by

§	$13 million increase at Sempra South American Utilities driven primarily by higher rates and volumes at both Luz del Sur and Chilquinta Energía, offset by foreign currency exchange rate effects.

Our utilities’ cost of electric fuel and purchased power increased by $349 million (18%) to $2.3 billion in 2014 compared to 2013 primarily due to:

§	$290 million increase at SDG&E, which we discuss below; and

§	$59 million increase at Sempra South American Utilities driven primarily by higher rates and volumes at both Luz del Sur and Chilquinta Energía, offset by foreign currency exchange rate effects.

We discuss the changes in electric revenues and the cost of electric fuel and purchased power for SDG&E in more detail below.

Natural Gas Revenues

In 2015, Sempra Energy’s natural gas revenues decreased by $453 million (10%) to $4.1 billion, and the cost of natural gas decreased by $624 million (35%) to $1.1 billion. The decrease in natural gas revenues included

§	decreases in cost of natural gas sold at both SoCalGas and SDG&E, as we discuss below; and

§	$28 million lower revenues at Sempra Mexico primarily due to foreign currency effects and lower natural gas prices at Ecogas; offset by

§	$65 million higher revenues from CPUC-authorized 2015 attrition at the California Utilities;

§	$45 million higher recovery of costs at SoCalGas associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses;

§	$19 million increase at SoCalGas from a retroactive increase, approved by the CPUC in 2015, in authorized GRC revenue requirement for years 2012 through 2014 due to increased rate base; and

§	$13 million higher regulatory awards at SoCalGas.

In 2014 compared to 2013, Sempra Energy’s natural gas revenues increased by $151 million (3%) to $4.5 billion, and the cost of natural gas increased by $112 million (7%) to $1.8 billion. The increase in natural gas revenues included

§	increases in cost of natural gas sold at both SoCalGas and SDG&E, as we discuss below;

§	increases of $52 million and $8 million at SoCalGas and SDG&E, respectively, in authorized revenues from 2014 attrition; and

§	$30 million higher revenues from the advanced metering infrastructure project at SoCalGas; offset by

§	$30 million favorable impact on the California Utilities’ 2013 revenues from the retroactive application of the 2012 GRC decision for the period from January 2012 through December 2012; and

§	$18 million lower recovery of costs at SoCalGas associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses.

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. In addition to the change in cost, electric revenues recorded during a period are impacted by customer billing cycles causing a difference between customer billings and recorded or 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
ELECTRIC DISTRIBUTION AND TRANSMISSION
(Volumes in millions of kilowatt-hours, dollars in millions)
	Years ended December 31,
	2015						2014					2013
Customer class	Volumes		Revenue				Volumes		Revenue			Volumes		Revenue
Residential		7,143		$	1,486			7,338		$	1,370		7,392		$	1,283
Commercial		6,877			1,508			6,974			1,418		6,722			1,080
Industrial		2,161			380			2,067			342		1,962			257
Direct access(1)		3,652			230			3,648			205		3,593			151
Street and highway lighting		83			15			88			15		87			12
		19,916			3,619			20,115			3,350		19,756			2,783
CAISO shared transmission revenue - net(2)					292						162					268
Other revenues					213						205					172
Balancing accounts					(405	)					68					314
Total(3)				$	3,719					$	3,785				$	3,537

(1)	Tariffs for the Direct Access program, which offers all customers the option to purchase their electric commodity services from a third-party Energy Service Provider instead of continuing to receive these services from SDG&E, increased in both 2015 and 2014.
(2)	California Independent System Operator (CAISO). CAISO shared transmission revenue changes are primarily due to timing differences offset by corresponding changes in balancing accounts.
(3)	Includes sales to affiliates of $8 million in 2015, $10 million in 2014 and $9 million in 2013.

SDG&E’s electric revenues decreased by $66 million (2%) to $3.7 billion in 2015 primarily due to:

§	$158 million lower cost of electric fuel and purchased power, including:

□	a decrease in cost of purchased power due to declining natural gas prices, and

□	a decrease in consumption due to energy efficiency initiatives, including an increase in rooftop solar installations, offset by

□	an increase from the incremental purchase of renewable energy at higher prices; and

§	$57 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; offset by

§	$52 million higher authorized revenues from electric transmission.

In 2014 compared to 2013, electric revenues increased by $248 million (7%) to $3.8 billion at SDG&E, primarily due to:

§	$290 million increase in cost of electric fuel and purchased power, including:

□	an increase in purchased power primarily due to the incremental purchase of renewable energy at higher prices, offset by

□	a decrease in cost of electric fuel primarily due to planned outages at SDG&E-owned generation facilities;

§	$39 million increase in authorized revenues from 2014 attrition; and

§	$32 million higher authorized revenues from electric transmission; offset by

§	$61 million favorable impact on 2013 revenues from the retroactive application of the 2012 GRC decision for the period from January 2012 through December 2012; and

§	$47 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses.

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 in 2013 that were allocated to SDG&E by the California Department of Water Resources (DWR). However, we do include the associated volumes and distribution revenues in the table above. The related operating agreement with the DWR expired at the end of 2013.

SDG&E and SoCalGas: Natural Gas Revenues and Cost of Natural Gas

The tables below 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
(Volumes in billion cubic feet, dollars in millions)
	Natural gas sales				Transportation				Total
Customer class	Volumes		Revenue		Volumes		Revenue		Volumes		Revenue
2015:
Residential		24	$	295		―	$	2		24	$	297
Commercial and industrial		14		96		8		14		22		110
Electric generation plants(1)		―		―		27		1		27		1
		38	$	391		35	$	17		73		408
Other revenues												40
Balancing accounts												52
Total(2)											$	500
2014:
Residential		25	$	304		―	$	2		25	$	306
Commercial and industrial		14		106		8		10		22		116
Electric generation plants(1)		―		―		26		2		26		2
		39	$	410		34	$	14		73		424
Other revenues												40
Balancing accounts												80
Total(2)											$	544
2013:
Residential		31	$	323		―	$	1		31	$	324
Commercial and industrial		15		98		9		13		24		111
Electric generation plants		―		―		25		15		25		15
		46	$	421		34	$	29		80		450
Other revenues												42
Balancing accounts												37
Total(2)											$	529

(1)

Lower electric generation plants revenue in 2015 and 2014 compared to 2013 is due to refunds of previous overcollections to adjust forecasted rates to actual.

(2)

Includes sales to affiliates of $2 million in 2015 and $3 million in each of 2014 and 2013.

In 2015, SDG&E’s natural gas revenues decreased by $44 million (8%) to $500 million, and the cost of natural gas decreased by $55 million (26%) to $153 million. The decrease in revenues was primarily due to:

§	lower cost of natural gas sold, as we discuss below; offset by

§	$8 million increase in revenues from CPUC-authorized 2015 attrition.

In 2014 compared to 2013, SDG&E’s natural gas revenues increased by $15 million (3%) to $544 million, and the cost of natural gas increased by $4 million (2%) to $208 million. The increase in revenues was primarily due to:

§	higher cost of natural gas sold, offset by lower volumes, as we discuss below; and

§	$8 million increase in authorized revenues from 2014 attrition; offset by

§	$5 million favorable impact from the retroactive application of the 2012 GRC decision for the period from January 2012 through December 2012.

SDG&E’s average cost of natural gas was $4.05 per thousand cubic feet (Mcf) for 2015, $5.44 per Mcf for 2014 and $4.49 per Mcf for 2013. In 2015, the 26-percent decrease of $1.39 per Mcf resulted in lower revenues and cost of $52 million compared to 2014.

In 2014, the 21-percent increase of $0.95 per Mcf resulted in higher revenues and cost of $36 million compared to 2013. The increase in the cost of natural gas sold was offset by lower demand for natural gas primarily from a warmer winter in 2014 compared to the same period in 2013, which resulted in lower revenues and cost of $32 million.

SOCALGAS
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
	Natural gas sales				Transportation				Total
Customer class	Volumes		Revenue		Volumes		Revenue		Volumes		Revenue
2015:
Residential		198	$	2,037		3	$	15		201	$	2,052
Commercial and industrial		93		622		282		271		375		893
Electric generation plants		―		―		193		41		193		41
Wholesale		―		―		156		27		156		27
		291	$	2,659		634	$	354		925		3,013
Other revenues												181
Balancing accounts												295
Total(1)											$	3,489
2014:
Residential		195	$	2,170		3	$	16		198	$	2,186
Commercial and industrial		92		743		293		260		385		1,003
Electric generation plants		―		―		211		42		211		42
Wholesale		―		―		150		24		150		24
		287	$	2,913		657	$	342		944		3,255
Other revenues												103
Balancing accounts												497
Total(1)											$	3,855
2013:
Residential		234	$	2,204		2	$	8		236	$	2,212
Commercial and industrial		100		691		293		242		393		933
Electric generation plants		―		―		200		44		200		44
Wholesale		―		―		170		27		170		27
		334	$	2,895		665	$	321		999		3,216
Other revenues												101
Balancing accounts												419
Total(1)											$	3,736

(1)

Includes sales to affiliates of $75 million in 2015, $69 million in 2014 and $70 million in 2013.

In 2015, SoCalGas’ natural gas revenues decreased by $366 million (9%) to $3.5 billion, and the cost of natural gas decreased by $528 million (36%) to $921 million. The revenue decrease included

§	the decrease in the cost of natural gas sold, as we discuss below; offset by

§	$57 million higher revenues from CPUC-authorized 2015 attrition;

§	$45 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses;

§	$19 million increase from a retroactive increase, approved by the CPUC in 2015, in authorized GRC revenue requirement for years 2012 through 2014 due to increased rate base; and

§	$13 million higher regulatory awards.

In 2014 compared to 2013, SoCalGas’ natural gas revenues increased by $119 million (3%) to $3.9 billion, and the cost of natural gas increased by $87 million (6%) to $1.4 billion. The revenue increase included

§	an increase in the market price of natural gas purchased, offset by lower volumes, as we discuss below;

§	$52 million increase in authorized revenues from 2014 attrition; and

§	$30 million higher revenues from the advanced metering infrastructure project; offset by

§	$25 million favorable impact from the retroactive application of the 2012 GRC decision for the period from January 2012 through December 2012; and

§	$18 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses.

SoCalGas’ average cost of natural gas was $3.18 per Mcf for 2015, $5.06 per Mcf for 2014 and $4.08 per Mcf for 2013. In 2015, the 37-percent decrease of $1.88 per Mcf resulted in lower revenues and cost of $543 million compared to 2014. The decrease in the cost of natural gas sold was offset by higher sales volumes, which resulted in higher revenues and cost of $15 million. The higher sales volumes were mainly driven by cooler weather in 2015 compared to the same period in 2014.

In 2014, the 24-percent increase of $0.98 per Mcf resulted in higher revenues and cost of $280 million compared to 2013. The increase in the cost of natural gas sold was offset by lower demand for natural gas primarily from a warmer winter in 2014 compared to the same period in 2013, which resulted in lower revenues and cost of $193 million.

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 bases for the tariffs do not meet the requirements necessary for regulatory accounting treatment under applicable U.S. GAAP. 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
(Dollars in millions)
	Years ended December 31,
	2015				2014				2013
	Volumes		Revenue		Volumes		Revenue		Volumes		Revenue
Natural Gas Sales (billion cubic feet):
Sempra Mexico – Ecogas		25	$	81		24	$	109		24	$	97
Sempra Natural Gas:
Mobile Gas (including transportation)		47		85		38		89		40		88
Willmut Gas		3		18		3		24		3		21
Total		75	$	184		65	$	222		67	$	206

Electric Sales (million kilowatt hours):
Sempra South American Utilities:
Luz del Sur		7,549	$	885		7,287	$	854		6,984	$	785
Chilquinta Energía		2,887		504		2,944		530		2,856		537
		10,436		1,389		10,231		1,384		9,840		1,322
Other service revenues				58				50				61
Total			$	1,447			$	1,434			$	1,383

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
(Dollars in millions)
	Years ended December 31,
	2015					2014					2013
REVENUES
Sempra South American Utilities	$	97		10	%	$	100		8	%	$	112		9	%
Sempra Mexico		588		60			709		55			578		46
Sempra Renewables		36		4			35		3			82		7
Sempra Natural Gas		550		56			866		68			799		64
Intersegment revenues, eliminations
and adjustments(1)		(294	)	(30	)		(433	)	(34	)		(323	)	(26	)
Total revenues	$	977		100	%	$	1,277		100	%	$	1,248		100	%
COST OF SALES(2)
Sempra South American Utilities	$	22		7	%	$	11		2	%	$	―		―	%
Sempra Mexico		221		66			350		63			253		58
Sempra Renewables		―		―			―		―			3		1
Sempra Natural Gas		375		112			617		112			497		114
Eliminations and adjustments(1)		(283	)	(85	)		(426	)	(77	)		(318	)	(73	)
Total cost of natural gas, electric fuel
and purchased power	$	335		100	%	$	552		100	%	$	435		100	%

Sempra South American Utilities	$	64		43	%	$	68		42	%	$	84		47	%
Sempra Mexico		15		10			14		8			10		6
Sempra Natural Gas		79		54			89		55			91		51
Eliminations and adjustments(1)		(10	)	(7	)		(8	)	(5	)		(7	)	(4	)
Total other cost of sales	$	148		100	%	$	163		100	%	$	178		100	%

(1)

Includes eliminations of intercompany activity.

(2)

Excludes depreciation and amortization, which are shown separately on the Consolidated Statements of Operations.

Revenues from our energy-related businesses decreased by $300 million (23%) to $977 million in 2015. The decrease included

$316 million decrease at Sempra Natural Gas mainly from lower natural gas prices and volumes and lower power revenues due to the sale of the remaining block of Mesquite Power and a related power sale contract in April 2015, as well as from the deconsolidation of Cameron LNG, LLC as of October 1, 2014; and

$121 million lower revenues at Sempra Mexico primarily due to lower natural gas prices and volumes in its gas business and lower power prices and volumes and capacity revenues in its power business, offset by higher transportation revenues from a section of the Sonora natural gas pipeline that commenced operations in the fourth quarter of 2014; offset by

§	$139 million primarily from lower intercompany eliminations associated with sales between Sempra Natural Gas and Sempra Mexico.

At Sempra South American Utilities, revenues decreased by $3 million in 2015 primarily due to foreign currency effects, offset by higher revenues associated with the transfer of certain non-regulated customers from Chilquinta Energía. Those revenues were included in “Electric Revenues” in prior years.

In 2014 compared to 2013, revenues from our energy-related businesses increased by $29 million (2%) to $1.3 billion. The increase included

§	$131 million higher revenues at Sempra Mexico primarily due to higher natural gas and power prices and volumes, and higher transportation revenues from the start of operations of a section of the Sonora natural gas pipeline; and

§	$67 million increase at Sempra Natural Gas mainly from the favorable impact of higher natural gas prices and volumes in 2014 from its LNG marketing operations, offset by lower revenues from its natural gas marketing activities; offset by

§	$110 million higher intercompany eliminations primarily associated with sales between Sempra Natural Gas and Sempra Mexico; and

§	$47 million lower revenues at Sempra Renewables mainly due to the deconsolidation of Mesquite Solar 1 and Copper Mountain Solar 2 in 2013.

The cost of natural gas, electric fuel and purchased power for our energy-related businesses decreased by $217 million (39%) to $335 million in 2015 primarily due to:

§	$242 million decrease at Sempra Natural Gas primarily due to lower natural gas costs and volumes and lower electric fuel costs due to the sale of the remaining block of Mesquite Power in April 2015; and

§	$129 million decrease at Sempra Mexico primarily due to lower natural gas costs and volumes; offset by

§	$143 million primarily from lower intercompany eliminations of costs associated with sales between Sempra Natural Gas and Sempra Mexico.

The cost of natural gas, electric fuel and purchased power for our energy-related businesses increased by $117 million (27%) to $552 million in 2014 compared to 2013 primarily due to:

§	$120 million increase at Sempra Natural Gas primarily due to higher natural gas costs and volumes; and

§	$97 million increase at Sempra Mexico primarily due to higher natural gas costs and volumes; offset by

§	$108 million higher intercompany eliminations of costs primarily associated with sales between Sempra Natural Gas and Sempra Mexico.

Operation and Maintenance

In the table below, we provide a breakdown of our operation and maintenance expenses by segment.

OPERATION AND MAINTENANCE
(Dollars in millions)
	Years ended December 31,
	2015					2014				2013
California Utilities:
SDG&E	$	1,017		35	%	$	1,076	37	%	$	1,157	39	%
SoCalGas		1,370		47			1,321	45			1,324	44
Sempra International:
Sempra South American Utilities		160		6			173	6			170	6
Sempra Mexico		126		4			121	4			124	4
Sempra U.S. Gas & Power:
Sempra Renewables		50		2			50	2			46	1
Sempra Natural Gas		177		6			181	6			167	6
Parent and other(1)		(5	)	―			13	―			7	―
Total operation and maintenance	$	2,895		100	%	$	2,935	100	%	$	2,995	100	%

(1)

Includes intercompany eliminations recorded in consolidation.

Sempra Energy Consolidated

Our operation and maintenance expenses decreased by $40 million (1%), remaining at $2.9 billion in 2015 primarily due to:

§	$59 million decrease at SDG&E, which we discuss below; and

§	$18 million decrease at Parent and Other primarily due to lower employee benefit and deferred compensation costs; offset by

§	$49 million increase at SoCalGas, which we discuss below.

Our operation and maintenance expenses decreased by $60 million (2%) to $2.9 billion in 2014 compared to 2013 primarily due to:

§	$81 million decrease at SDG&E, which we discuss below; and

§	$3 million decrease at SoCalGas, which we discuss below; offset by

§	$14 million increase at Sempra Natural Gas primarily due to higher operating expenses at its LNG operations.

SDG&E

SDG&E’s operation and maintenance expenses decreased by $59 million (5%) to $1.0 billion in 2015 primarily due to:

§	$53 million lower expenses associated with CPUC-authorized refundable programs, for which all costs incurred are fully recovered in revenue (refundable program expenses); and

§	$8 million lower non-refundable operating costs, including $11 million lower major maintenance costs at its electric generating facilities, as well as labor, contract services and administrative and support costs.

SDG&E’s operation and maintenance expenses decreased by $81 million (7%) to $1.1 billion in 2014 compared to 2013 primarily due to:

§	$44 million lower expenses associated with CPUC-authorized refundable programs, including $61 million due to lower operation and maintenance expenses at SONGS, for which all costs incurred are fully recovered in revenue (refundable program expenses);

§	$23 million lower non-refundable operating costs, including labor, contract services and administrative and support costs; and

§	$8 million lower litigation expense.

SoCalGas

Operation and maintenance expenses at SoCalGas increased in 2015 by $49 million (4%) to $1.4 billion, primarily due to $45 million higher expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses).

SoCalGas’ operation and maintenance expenses decreased by $3 million, remaining at $1.3 billion in 2014 compared to 2013 primarily due to:

§	$18 million lower expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses); offset by

§	$9 million higher non-refundable operating costs, including labor, contract services and administrative and support costs; and

§	$7 million insurance recovery in 2013 of previously expensed costs.

Depreciation and Amortization

Sempra Energy Consolidated

Our depreciation and amortization expense was

§	$1,250 million in 2015

§	$1,156 million in 2014

§	$1,113 million in 2013

The increase of $94 million (8%) in 2015 was primarily due to:

$74 million higher depreciation and amortization at SDG&E mainly from $42 million from the start of amortization of SONGS regulatory assets and from higher utility plant base. As we discuss in Note 13 of the Notes to Consolidated Financial Statements, based on an amended settlement agreement approved by the CPUC in 2014, SDG&E is authorized to recover in rates its remaining investment in SONGS, including base plant and construction work in progress; and

§	$30 million higher depreciation at SoCalGas from higher utility plant base; offset by

§	$12 million lower depreciation expense at Sempra Natural Gas primarily due to the deconsolidation of Cameron LNG, LLC as of October 1, 2014.

The increase of $43 million (4%) in 2014 compared to 2013 was primarily due to:

§	$33 million higher depreciation at SoCalGas from higher utility plant base;

§	$18 million net increase in depreciation at SDG&E mainly from higher utility plant base, offset by lower depreciation from the retirement of SONGS; and

§	lower depreciation in 2013 of $18 million at SDG&E and $15 million at SoCalGas due to the retroactive application to the period of January 1 to December 2012 of the extension of the useful lives of depreciable assets as adopted in the 2012 GRC; offset by

§	$16 million lower depreciation at Sempra Renewables mainly related to the deconsolidation of Mesquite Solar 1 and Copper Mountain Solar 2 in 2013; and

§	$20 million lower depreciation expense at Sempra Natural Gas largely due to the classification of the second block of the Mesquite Power plant as an asset held for sale in January 2014.

Plant Closure Adjustment (Loss)

SDG&E has a 20-percent ownership interest in SONGS, a nuclear generating facility near San Clemente, California. SONGS Units 2 and 3 were shut down in early 2012 due to steam generator issues and, in June 2013, Edison, the majority owner and operator of SONGS, made the decision to permanently retire these two units. In the second quarter of 2013, SDG&E recorded a pretax charge of $200 million ($119 million after-tax), which represents the portion of SDG&E’s investment in SONGS and associated costs that management estimated may not be recovered in rates based on CPUC precedent. In 2014, SDG&E recorded a $6 million charge ($4 million after-tax, not including a $17 million charge to reduce certain tax regulatory assets that we discuss in “Income Taxes” below) to adjust the total loss from plant closure (in addition to the amount recorded in 2013), based on a settlement agreement (approved by the CPUC in November 2014) to the SONGS Order Instituting Investigation (OII) into the SONGS outage. In the first quarter of 2015, SDG&E recorded a $21 million pretax ($13 million after-tax) reduction to the loss from plant closure, based on CPUC approval of a compliance filing related to SDG&E’s authorized recovery of its investment in SONGS. In the fourth quarter of 2015, SDG&E recorded a $5 million pretax ($2 million after-tax) reduction to the loss from plant closure, based on a settlement with NEIL to resolve all of SONGS’ insurance claims arising out of the failures of the replacement steam generators. We discuss SONGS further in Notes 13 and 15 of the Notes to Consolidated Financial Statements.

Gain on Sale of Equity Interests and Assets

Gain on sale of equity interests and assets includes, in 2015, a $61 million ($36 million after-tax) gain on the sale of the remaining 625-MW block of the Mesquite Power plant and a related power sale contract, and an $8 million ($5 million after-tax) gain on the sale of the Rosamond Solar development project, and in 2013, the $74 million ($44 million after-tax) gain on the sale of the first 625-MW block of the Mesquite Power plant.

Also included in this line item are gains on the sale of 50-percent equity interests in 2014 and 2013 as follows:

2014:

§	$27 million ($16 million after-tax) for Copper Mountain Solar 3

§	$19 million ($14 million after-tax) for the first phase of the Energía Sierra Juárez Wind project

§	$14 million ($8 million after-tax) for the Broken Bow 2 Wind project

2013:

§	$36 million ($22 million after-tax) for Mesquite Solar 1

§	$4 million ($2 million after-tax) for Copper Mountain Solar 2

Equity Earnings, Before Income Tax

Equity earnings from our equity method investments were

§	$104 million in 2015

§	$81 million in 2014

§	$31 million in 2013

The increase of $23 million in equity earnings in 2015 was primarily due to:

§	$19 million higher equity earnings from Rockies Express mainly due to east-to-west capacity placed in service in 2015; and

§	$4 million higher earnings at Sempra Renewables due to higher earnings from increased solar capacity, offset by lower earnings from decreased production at wind projects.

The increase in equity earnings in 2014 compared to 2013 was primarily due to:

§	$20 million equity earnings in 2014 compared to $12 million equity losses in 2013 from investments at Sempra Renewables, including Mesquite Solar 1, the California solar partnership, Fowler Ridge 2 Wind and Copper Mountain Solar 2; and

§	$13 million higher equity earnings from Rockies Express.

We provide further details about equity method investments in Note 4 of the Notes to Consolidated Financial Statements.

Other Income, Net

Sempra Energy Consolidated

Other income, net, was

§	$126 million in 2015

§	$137 million in 2014

§	$140 million in 2013

Other income, net, includes equity-related AFUDC at the California Utilities and regulated entities at Sempra Mexico and Sempra Natural Gas; interest on regulatory balancing accounts; gains and losses from our investments and interest rate swaps; foreign currency gains and losses; electrical infrastructure relocation income in Peru; and other, sundry amounts. The investment activity is on dedicated assets in support of certain executive benefit plans, as we discuss in Note 7 of the Notes to Consolidated Financial Statements.

Other income, net, decreased $11 million (8%) in 2015 and included the following activity:

§	$24 million lower investment gains in 2015 on dedicated assets in support of our executive retirement and deferred compensation plans; and

§	$14 million lower electrical infrastructure income in Peru; offset by

§	$11 million lower net losses on interest rate and foreign exchange instruments in 2015;

§	$9 million higher income from the sale of other investments;

§	$8 million lower foreign currency losses in 2015; and

§	$1 million increase in equity-related AFUDC, including

□	$10 million increase at SoCalGas, offset by

□	$10 million decrease at Sempra Mexico related to construction of the Sonora natural gas pipeline.

In 2014 compared to 2013, other income, net, decreased by $3 million (2%) to $137 million and included the following activity:

§	$15 million losses on interest rate and foreign exchange instruments in 2014 compared to $17 million gains in 2013;

§	$12 million higher foreign currency losses, primarily at Sempra Mexico; and

§	$12 million lower investment gains on dedicated assets in support of our executive retirement and deferred compensation plans; offset by

§	$31 million increase in equity-related AFUDC, including

□	$24 million increase at Sempra Mexico related to construction of the Sonora natural gas pipeline, and

□	$9 million increase at SoCalGas; and

§	$17 million higher income from relocation of electrical infrastructure in Peru.

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
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Sempra Energy Consolidated		$	561		$	554		$	559
SDG&E			204			202			197
SoCalGas			84			69			69

The increase of $7 million (1%) at Sempra Energy Consolidated in 2015 was primarily due to:

§	$24 million increase in long-term debt interest at Parent and Other primarily due to debt issuances in 2014 and 2015, net of maturities; and

§	$15 million increase at SoCalGas primarily due to debt issuances in 2014 and 2015; offset by

§	$33 million increase in capitalized interest at Sempra Natural Gas primarily related to its investment in Cameron LNG JV, which has not commenced its planned principal operations.

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
(Dollars in millions)
	Years ended December 31,
	2015					2014					2013
	Income		Effective			Income		Effective			Income		Effective
	tax		income			tax		income			tax		income
	expense		tax rate			expense		tax rate			expense		tax rate
Sempra Energy Consolidated	$	341		20	%	$	300		20	%	$	366		26	%
SDG&E		284		32			270		34			191		31
SoCalGas		138		25			139		29			116		24

Sempra Energy Consolidated

Sempra Energy’s income tax expense increased in 2015 due to higher pretax income. The effective income tax rate remained the same in 2015. However, the effective income tax rate was affected by:

§	$21 million higher favorable resolution of prior years’ income tax items in 2015;

§	$20 million U.S income tax expense in 2015 on the planned repatriation of current year earnings from certain non-U.S. subsidiaries, compared to $38 million in 2014, discussed below; and

§	$17 million charge in 2014 to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS, as we discuss in Note 13 of the Notes to Consolidated Financial Statements; offset by

§	$25 million tax benefit in 2014 due to the release of Louisiana state valuation allowance against a deferred tax asset associated with Cameron LNG developments.

Sempra Energy’s income tax expense decreased in 2014 compared to 2013 due to a lower effective income tax rate, offset by higher pretax income. The lower effective income tax rate was primarily due to:

§	$63 million income tax expense recorded in the first quarter of 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings. We discuss the stock offerings further in Note 1 of the Notes to Consolidated Financial Statements;

§	higher income tax benefit in 2014 from foreign currency translation and inflation adjustments;

§	$25 million tax benefit in 2014 due to the release of Louisiana state valuation allowance against a deferred tax asset associated with Cameron LNG developments; and

§	higher deferred income tax benefits related to renewable energy projects; offset by

§	$38 million U.S. income tax expense in 2014 on the repatriation of a portion of 2014 earnings from certain non-U.S. subsidiaries; and

§	$17 million charge in 2014 to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS.

Consolidated results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE’s pretax earnings, which impacts Sempra Energy Consolidated’s and SDG&E’s effective income tax rates. For 2015, 2014 and 2013, the impacts on Sempra Energy Consolidated’s and SDG&E’s effective income tax rates were not material. We discuss Otay Mesa VIE further in Note 1 of the Notes to Consolidated Financial Statements.

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 2016, we anticipate that Sempra Energy Consolidated’s effective income tax rate will be approximately 28 percent compared to 20 percent in 2015. In the years 2017 through 2020, we anticipate that Sempra Energy Consolidated’s effective income tax rate will be approximately 32 percent.

The increase in the forecasted effective income tax rates is primarily due to a forecasted increase in pretax book income without a proportional increase in the forecasted flow-through deductions at the California Utilities, and the effective income tax rate in 2015 was impacted by significant one-time items that could not be reliably forecasted. Flow-through deductions are subject to review by the CPUC and, at the CPUC’s discretion, the flow-through benefits of these items could be changed, which could have a material adverse impact on Sempra Energy’s and the California Utilities’ earnings, financial condition and cash flow. The income tax effects of items that cannot be reliably forecasted are not factored into the forecasted effective tax rates above.

SDG&E

SDG&E’s income tax expense increased in 2015 due to higher pretax income, offset by a lower effective tax rate, primarily from the $17 million charge in 2014 to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS.

SDG&E’s income tax expense increased in 2014 compared to 2013 due to a higher effective tax rate and higher pretax income. Pretax income in 2013 included a $200 million loss from the early closure of SONGS, offset by the favorable impact of the retroactive application of the 2012 GRC in 2013. The higher effective tax rate was primarily due to:

§	$17 million charge in 2014 to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS; offset by

§	higher favorable resolution of prior years’ income tax items in 2014.

In the years 2016 through 2020, we anticipate that SDG&E’s effective income tax rate will be approximately 37 percent compared to 32 percent in 2015. The increase in the forecasted effective income tax rates is primarily due to a forecasted increase in pretax book income without a proportional increase in the forecasted flow-through deductions, and the effective income tax rate in 2015 was impacted by significant one-time items that could not be reliably forecasted. The income tax effects of items that cannot be reliably forecasted are not factored into the forecasted effective tax rates above.

SoCalGas

SoCalGas’ income tax expense decreased slightly in 2015 due to a lower effective tax rate, offset by higher pretax income. The lower effective tax rate was primarily due to:

§	$10 million higher favorable resolution of prior years’ income tax items in 2015;

§	higher deductions for certain repairs expenditures that are capitalized for financial statement purposes; and

§	higher deductions for self-developed software expenditures.

SoCalGas’ income tax expense increased in 2014 compared to 2013 due to a higher effective tax rate, offset by slightly lower pretax income. The higher effective tax rate was primarily due to:

§	$15 million lower favorable resolution of prior years’ income tax items in 2014;

§	higher unfavorable impact on our effective tax rate in 2014 from the reversal through book depreciation of previously recognized tax benefits for a certain portion of utility fixed assets; and

§	lower deductions for self-developed software expenditures.

In the years 2016 through 2020, we anticipate that SoCalGas’ effective income tax rate will range from 31 percent to 34 percent compared to 25 percent in 2015. The increase in the forecasted effective income tax rates is primarily due to a forecasted increase in pretax book income without a proportional increase in the forecasted flow-through deductions, and the effective income tax rate in 2015 was impacted by significant one-time items that could not be reliably forecasted. The income tax effects of items that cannot be reliably forecasted are not factored into the forecasted effective tax rates above.

The following items are subject to flow-through treatment at the California Utilities:

§	repairs expenditures related to a certain portion of utility plant assets

§	the equity portion of AFUDC

§	a portion of the cost of removal of utility plant assets

§	utility self-developed software expenditures

§	depreciation on a certain portion of utility plant assets

§	state income taxes

The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico has similar flow-through treatment.

Tax Reform

United States. In December 2015, the Protecting Americans from Tax Hikes Act of 2015 (2015 Tax Act) was signed into law. The 2015 Tax Act provided for retroactive extension of certain business income tax provisions that had expired at the end of 2014, including permanent extension of the research credit. The 2015 Tax Act also extended 50-percent bonus depreciation through 2017, and provided for 40-percent bonus depreciation in 2018 and 30-percent bonus depreciation in 2019. The impact of bonus depreciation is discussed below.

In December 2014, the Tax Increase Prevention Act of 2014 (2014 Tax Act) was signed into law. The 2014 Tax Act included a one-year retroactive extension of certain business income tax provisions that had expired at the end of 2013, including the research credit and 50-percent bonus depreciation. The impact of bonus depreciation is discussed below.

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 resulted in a $6 million income tax benefit. However, as the 2012 Tax Act was not signed into law as of December 31, 2012, we treated the extension of the look-through rule as a 2013 event, and recorded the related income tax benefit for 2012 in the first quarter of 2013. The 2012 Tax Act also extended 50-percent bonus depreciation for qualified property placed in service before January 1, 2014, the impact of which we discuss below.

Due to the extension of bonus depreciation, Sempra Energy generated a U.S. federal net operating loss (NOL) in years 2011 through 2014. Because of the NOLs and U.S. federal income tax credits carried forward, Sempra Energy made no U.S. federal income tax payments for tax years 2011 through 2015. Based on current projections, Sempra Energy does not expect any of its NOL or income tax credits to expire prior to the end of the carryforward period, as allowed under current U.S. federal income tax law. SDG&E and SoCalGas both generated a large U.S. federal NOL in 2011 and 2012 primarily due to bonus depreciation. On a separate return basis, SDG&E fully utilized its NOL in 2015. Because bonus depreciation only creates a temporary difference between U.S. federal income tax returns and U.S. GAAP financial statements, it does not impact Sempra Energy’s nor the California Utilities’ effective income tax rates. We expect larger U.S. federal income tax payments in the future as these temporary differences reverse. In addition, bonus depreciation increases the deferred income tax liability component of SDG&E’s and SoCalGas’ rate base, which reduces rate base.

Peru. On December 31, 2014, the Peruvian government passed a tax reform law, effective on January 1, 2015. Among other changes, the law imposed a gradual decrease in the corporate income tax rate from 30 percent in 2014 to 26 percent in 2019 and beyond, as well as a gradual increase in the dividend withholding tax rate from 4.1 percent in 2014 to 9.3 percent in 2019 and beyond. To reflect the impact of the decrease to the Peruvian corporate income tax rate, we remeasured our Peruvian deferred tax balances, resulting in an additional $18 million of deferred tax benefit, which we recorded in the fourth quarter of 2014. There was no immediate impact of the increase to the Peruvian dividend withholding tax rate, because the withholding tax is accrued at the shareholder level when Peruvian earnings are actually distributed.

Chile. The 2014 Chilean Tax Reform Bill (Tax Reform Bill) became effective on September 29, 2014. The law imposed a gradual increase in the corporate income tax rate between 2014 and 2018, from 21 percent to 27 percent. To reflect the impact of the change in tax law, we remeasured our Chilean deferred tax balances, which resulted in an additional $6 million of deferred tax expense, which we recorded in the third quarter of 2014. The Tax Reform Bill also imposed a tax on earnings distributed to non-Chilean shareholders. However, since Sempra Energy intends to indefinitely reinvest the cumulative Chilean earnings, there is no impact from the Tax Reform Bill’s shareholder level income tax.

Mexico. In December 2013, the Mexican Congress passed tax reform legislation with the following impacts on Sempra Energy and our Sempra Mexico segment:

§	Higher Corporate Tax Rate: The new corporate income tax rate is 30 percent for 2014 and future years. In 2013, we recorded $13 million additional income tax expense related to the revaluation of deferred tax liabilities.

Tax Consolidation: The tax reform legislation removed the ability to utilize the NOLs of one company to offset the tax liabilities of another within a Mexican consolidated group (deconsolidation rule). As a result of the deconsolidation rule and IEnova’s corporate reorganization, we made a payment of $81 million in 2014 against current tax liabilities and taxes on prior intercompany distributions in excess of previously taxed earnings.

10-Percent Dividends Tax: The law instituted a “corporate” tax on dividends, payable by the Mexican entity that distributes the dividend to its foreign shareholder, which increased Mexico’s income tax rate to an effective 37 percent. Under the law, this tax is reduced or offset in accordance with bilateral tax treaties. The dividends from our Mexican entities to Sempra Energy will be to a country which has a bilateral tax treaty with Mexico that we expect will fully offset the tax. Accordingly, we do not expect this rule to have a material financial impact.

Repatriation of Foreign Earnings

Repatriated earnings are subject to U.S. income tax, and repatriation from Peru is subject to local country withholding tax. We plan to repatriate current year earnings from certain of our non-U.S. subsidiaries in Peru, and accordingly, we have accrued U.S. income tax expense on these earnings. Due to IEnova’s potential acquisition of its joint venture partner’s 50-percent interest in GdC, which we discuss in Note 3 of the Notes to Consolidated Financial Statements, we no longer plan to repatriate current year earnings from our non-U.S. subsidiaries in Mexico. We made distributions of approximately $288 million and $200 million from our non-U.S. subsidiaries in 2014 and 2013, respectively. Approximately $100 million of the 2014 distribution and all of the 2013 distribution was from previously taxed income and therefore not subject to additional U.S. federal income tax. Except for the current year Peruvian earnings for which we have accrued U.S. income tax, we intend to continue to indefinitely reinvest our cumulative undistributed non-U.S. earnings through December 31, 2015. Therefore, we do not intend to use these cumulative undistributed earnings as a source of funding for U.S. operations.

Foreign Currency Exchange Rate and Inflation Impact on Income Taxes and Related Economic Hedging Activity

Our Mexican subsidiaries have U.S. dollar denominated cash balances, 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. Subsequent to the potential acquisition of PEMEX’s 50-percent interest in GdC by IEnova, which we discuss in Note 3 of the Notes to Consolidated Financial Statements, our exposure to foreign currency rate risk would likely increase and could have a material impact on our Mexican income tax expense. We utilize short-term foreign currency derivatives at our subsidiaries and at the consolidated level as a means to manage these exposures.

The income tax expense of our South American subsidiaries is similarly impacted by the factors we discuss above. Such impact was not material in 2015, 2014 or 2013.

We provide further discussion of our exposure to foreign currency rate and inflation risks below in “Factors Influencing Future Performance – Market Risk.”

For Sempra Energy Consolidated, the impacts at Sempra Mexico related to the factors described above are as follows:

MEXICAN CURRENCY AND INFLATION IMPACT ON INCOME TAXES AND RELATED ECONOMIC HEDGING ACTIVITY
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Income tax benefit (expense) on currency exchange
rate movement of monetary assets and liabilities	$	27		$	22		$	(6	)
Translation of non-U.S. deferred income tax balances		10			15			1
Income tax expense on inflation		(3	)		(3	)		―
Total impact included in Income Tax Benefit (Expense)		34			34			(5	)
After-tax (losses) gains on Mexican peso exchange rate
instruments (included in Other Income, Net)		(2	)		(17	)		4
Net impact on Sempra Energy Consolidated
Statements of Operations	$	32		$	17		$	(1	)

Equity Earnings, Net of Income Tax

Sempra Energy Consolidated

Equity earnings of unconsolidated subsidiaries, net of income tax, which are all from Sempra South American Utilities’ and Sempra Mexico’s equity method investments, were

§	$85 million in 2015

§	$38 million in 2014

§	$24 million in 2013

The increase of $47 million in 2015 was primarily due to:

§	start of operations in December 2014 of Los Ramones I, a pipeline that IEnova owns through GdC, a joint venture with PEMEX;

§	higher earnings from the Energía Sierra Juárez wind-powered electric generation facility commencing operations in the second quarter of 2015; and

§	equity-related AFUDC for the Los Ramones Norte pipeline project, which IEnova is developing under a joint venture with PEMEX and affiliates of PEMEX.

The increase in 2014 compared to 2013 was primarily due to $11 million equity losses in 2013 related to our investments in two Argentine natural gas utility holding companies, as we discuss in Note 4 of the Notes to Consolidated Financial Statements.

Earnings Attributable to Noncontrolling Interests

Sempra Energy Consolidated

Earnings attributable to noncontrolling interests were $98 million for 2015 compared to $100 million for 2014. The net change of $2 million included

§	$7 million decrease in earnings attributable to noncontrolling interests at Sempra South American Utilities, before adjustments for the effects of foreign currency translation; offset by

§	$6 million increase in earnings attributable to noncontrolling interests of IEnova in 2015.

Earnings attributable to noncontrolling interests were $100 million for 2014 compared to $79 million for 2013. The net change of $21 million included

§	$21 million increase in earnings attributable to noncontrolling interests of IEnova in 2014; and

§	$5 million increase in earnings attributable to noncontrolling interests at Sempra South American Utilities in 2014; offset by

§	$4 million decrease in earnings attributable to noncontrolling interest at Otay Mesa VIE in 2014.

SDG&E

In 2014 compared to 2013, earnings attributable to noncontrolling interest at Otay Mesa VIE decreased by $4 million (17%) to $20 million.

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

§	$47.56 in 2015

§	$45.98 in 2014

§	$45.03 in 2013

The increases in 2015 and 2014 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. We may also meet our cash requirements through the issuance of securities, distributions from our equity method investments and project financing.

Sempra Energy Consolidated cash and cash equivalents decreased by $167 million in 2015 to $403 million at December 31, 2015. Cash flows from operations for 2015 were $2.9 billion. Significant sources (uses) of cash from investing and financing activity that affected capital resources, liquidity and cash flows in 2015 included

Sources of cash:

§	$3 billion issuances of debt, including $444 million at SDG&E and $599 million at SoCalGas

§	$373 million net cash proceeds from Sempra Natural Gas’ sale of the remaining block of the Mesquite Power plant and a related power sale contract, and Sempra Renewables’ sale of the Rosamond Solar development project

§	$60 million withdrawals from the Nuclear Decommissioning Trust assets at SDG&E for SONGS decommissioning costs. We discuss the Nuclear Decommissioning Trusts further in Note 13 of the Notes to Consolidated Financial Statements

§	$43 million in net repayments of advances to unconsolidated affiliates

Uses of cash:

§	$(3.2) billion in expenditures for property, plant and equipment, including $(1.1) billion at SDG&E and $(1.4) billion at SoCalGas

§	$(1.9) billion of debt retirements and paydowns, including debt retirements of $(547) million at SDG&E

§	$(628) million common dividends paid

§	$(622) million net decrease in short-term debt

$(174) million for joint venture investments at Sempra Natural Gas, including $(113) million for Rockies Express to repay project debt and $(59) million for Cameron LNG JV, including $(49) million of capitalized interest on Sempra Natural Gas’ investment in Cameron LNG JV, which has not commenced its planned principal operations

We discuss these events in more detail later in this section.

Our lines of credit provide liquidity and support commercial paper. As we discuss in Note 5 of the Notes to Consolidated Financial Statements, Sempra Energy, Sempra Global (the holding company for our subsidiaries not subject to California utility regulation) and the California Utilities each have five-year revolving credit facilities, expiring in 2020. The agreements are syndicated broadly among 20 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 2015, including available unused credit on these three credit facilities at December 31, 2015. Our foreign operations have additional general purpose credit facilities, aggregating $1.1 billion at December 31, 2015. Available unused credit on these lines totaled $889 million at December 31, 2015.

AVAILABLE FUNDS AT DECEMBER 31, 2015
(Dollars in millions)
	Sempra Energy
	Consolidated			SDG&E			SoCalGas
Unrestricted cash and cash equivalents(1)		$	403		$	20		$	58
Available unused credit(2)			3,707			582			750

	(1	)	Amounts at Sempra Energy Consolidated include $301 million held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated, as we discuss below.
	(2	)	Available credit is the total available on Sempra Energy's, Sempra Global's and the California Utilities' credit facilities that we discuss in Note 5 of the Notes to Consolidated Financial Statements. Borrowings on the shared line of credit at SDG&E and SoCalGas are limited to $750 million for each utility and a combined total of $1 billion. SDG&E's available funds reflect commercial paper outstanding of $168 million supported by the line.

Sempra Energy Consolidated

We believe that these available funds, combined with cash flows from operations, distributions from equity method investments, proceeds from securities issuances, project financing and partnering in joint ventures will be adequate to fund operations, including to:

§	finance capital expenditures

§	meet liquidity requirements

§	fund shareholder dividends

§	provide funding to new business acquisitions or start-ups

§	repay maturing long-term debt

Sempra Energy and the California Utilities currently have ready access to the long-term debt markets and are not currently constrained in their ability to borrow at reasonable rates. However, changing economic conditions could affect the availability and cost of both short-term and long-term financing. Also, cash flows from operations may be impacted by the timing of commencement and completion of large projects at Sempra International and Sempra U.S. Gas & Power. 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 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.

At December 31, 2015 and 2014, our cash and cash equivalents held in non-U.S. jurisdictions that were unavailable to fund U.S. operations unless repatriated were $301 million and $469 million, respectively. We discuss repatriation in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” above.

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. However, changes in asset values may, along with a number of other factors such as changes to discount rates, assumed rates of returns, mortality tables, and regulations, impact funding requirements for pension and other postretirement benefit plans and SDG&E’s nuclear decommissioning trusts. At the California Utilities, funding requirements are generally recoverable in rates.

On February 19, 2016, our board of directors approved an increase to Sempra Energy’s quarterly common stock dividend to $0.755 per share ($3.02 annually), an increase of $0.055 per share ($0.22 annually) from $0.70 per share ($2.80 annually) authorized in February 2015. 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 20, 2015, our board of directors approved an increase to Sempra Energy’s quarterly common stock dividend to $0.70 per share ($2.80 annually), an increase of $0.04 per share ($0.16 annually) from $0.66 per share ($2.64 annually) authorized in February 2014. 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.

Short-Term Borrowings

Our short-term debt is primarily used to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures and new business acquisitions or start-ups. Our corporate short-term, unsecured promissory notes, or commercial paper, were our primary sources of short-term debt funding in 2015. At our California Utilities, short-term debt is used to meet working capital needs and temporarily finance capital expenditures.

The following table shows selected statistics for our commercial paper borrowings for 2015:

COMMERCIAL PAPER STATISTICS
(Dollars in millions)
	Sempra Energy Consolidated				SDG&E				SoCalGas
Amount outstanding at December 31, 2015		$	503			$	168			$	―
Weighted average interest rate at December 31, 2015			0.854	%			1.015	%			0.00	%

Maximum month-end amount outstanding during 2015(1)		$	1,940			$	414			$	220

Monthly weighted average amount outstanding during 2015		$	980			$	129			$	34
Monthly weighted average interest rate during 2015			0.55	%			0.383	%			0.145	%

(1)

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 during 2015 included

§	common stock dividend payments ($628 million) by Sempra Energy;

§	equity method investment of $113 million for Rockies Express; and

§	interest payments on debt (approximately $250 million); offset by

§	long-term debt issuance at Sempra Energy ($1.3 billion);

§	common stock dividends received from SDG&E ($300 million) and SoCalGas ($50 million); and

§	net cash proceeds from Sempra Natural Gas’ sale of the remaining block of the Mesquite Power plant and a related power sale contract ($347 million).

Master Limited Partnership

In June 2015, we announced that our Board of Directors authorized us to pursue the formation and initial public offering of a master limited partnership (MLP) to be called Sempra Partners, LP. Initially, the MLP was expected to own one or more of the following assets: an interest in a U.S. entity with contracts related to deliveries of LNG at the Energía Costa Azul regasification facility; interests in certain of Sempra Energy’s contracted renewable energy projects; or other assets with attributes attractive for inclusion in the MLP. We also expect to grant the MLP a right of first offer on certain LNG-related infrastructure projects, including our 50.2-percent interest in the first three trains of the Cameron natural gas liquefaction terminal and our 100-percent interest in the Cameron Interstate Pipeline, as well as our interests in certain contracted wind and solar projects. The possible offering would be subject to the final approval of our Board of Directors and market conditions.

In the second half of 2015, Sempra Energy submitted confidentially a Form S-1 registration statement to the Securities and Exchange Commission. The capital markets have been unfavorable for master limited partnership initial public offerings since mid-2015. As a result of the uncertain markets, we paused our efforts to move forward with an initial public offering to reevaluate whether and when to pursue an MLP. At the present time, market conditions are not conducive to moving forward with the offering and we have written off the expenses related to the transaction. There can be no assurance as to the timing or whether we will consummate any MLP transaction. Our announcement of this plan did not, and this disclosure does not, constitute an offer to sell or the solicitation of an offer to buy any securities and shall not constitute an offer, solicitation or sale in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of that jurisdiction.

California Utilities

SDG&E and SoCalGas expect that available funds, cash flows from operations and debt issuances will continue to be adequate to meet their working capital and capital expenditure requirements.

SoCalGas declared and paid common stock dividends of $50 million in 2015, $100 million in 2014 and $50 million in 2013. As a result of an increase in SoCalGas’ capital investment programs over the next few years, and an increase in SoCalGas’ authorized common equity weighting effective January 1, 2013 as approved by the CPUC in the most recent cost of capital proceeding, SoCalGas’ dividends on common stock declared on an annual historical basis may not be indicative of future declarations, and may be temporarily suspended over the next few years to maintain SoCalGas’ authorized capital structure during the periods of high capital investments.

In connection with the natural gas leak at the Aliso Canyon storage facility, as of February 24, 2016, 83 lawsuits have been filed against SoCalGas, some of which have also named Sempra Energy and, in derivative claims on behalf of Sempra Energy and SoCalGas, certain officers and directors of Sempra Energy and SoCalGas. In addition, the Los Angeles City Attorney and Los Angeles County Counsel have also filed a complaint on behalf of the people of the State of California against SoCalGas for public nuisance and violation of the California Unfair Competition Law. The California Attorney General, acting in her independent capacity and on behalf of the people of the State of California and the California Air Resources Board (CARB), joined that existing lawsuit. The complaint, as amended to include the California Attorney General, adds allegations of violations of certain California Health and Safety Code and California Government Code sections. The South Coast Air Quality Management District (SCAQMD) also filed a complaint against SoCalGas seeking civil penalties for alleged violations of several nuisance-related statutory provisions arising from the leak and delays in stopping the leak. On February 2, 2016, the Los Angeles District Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties for alleged failure to provide timely notice of the leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a), and for violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public. The costs of defending against these civil and criminal lawsuits and cooperating with these investigations, and any damages and civil and criminal fines and other penalties, if awarded or imposed, as well as costs of mitigating greenhouse gas (GHG) emissions from the actual natural gas released, could be significant and to the extent not covered by insurance, or if there were to be significant delays in receiving insurance recoveries, could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations. Also, higher operating costs and additional capital expenditures incurred by SoCalGas may not be recoverable in customer rates, which may have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations, cash flows, and financial condition.

We discuss the Aliso Canyon facility further in Note 15 of the Notes to Consolidated Financial Statements, and in “Factors Influencing Future Performance” below.

SDG&E declared and paid common stock dividends of $300 million in 2015 and $200 million in 2014. As a result of SDG&E’s large capital investment program, SDG&E did not pay common stock dividends to Sempra Energy in 2013. However, due to the completion of construction of the Sunrise Powerlink transmission power line in June 2012, SDG&E resumed the declaration and payment of dividends on its common stock in 2014.

In October 2013, SDG&E redeemed all of its outstanding preferred stock for $83 million (including call premium and accrued dividends), which we discuss further in Note 11 of the Notes to Consolidated Financial Statements.

On August 28, 2015, SDG&E redeemed, prior to maturity, certain outstanding long-term debt instruments with a total principal amount of $169 million. The coupon rates of these instruments ranged from 4.9 percent to 5.5 percent, with maturities ranging from 2021 to 2027.

SDG&E uses the Energy Resource Recovery Account (ERRA) balancing account to record the net of its actual cost incurred for electric fuel and purchased power and the amount billed to customers in rates. SDG&E’s ERRA balance was overcollected by $25 million at December 31, 2015, representing a $305 million turnaround from a $280 million undercollected balance at December 31, 2014. During 2015, several key events contributed to the improvement in the ERRA balance:

settlement reached with Nuclear Energy Insurance Limited (NEIL) for insurance claims covering power replacement costs associated with the permanent retirement of SONGS. Consistent with terms of the SONGS settlement, after reimbursement of legal fees and 5-percent allocation to shareholders, the net proceeds of $75 million were credited to ERRA; we discuss SONGS in Note 13 of the Notes to Consolidated Financial Statements

§	CPUC approval to access Nuclear Decommissioning Trust funds for reimbursement of nuclear decommissioning costs incurred in 2013 and 2014, as we discuss in Note 14 of the Notes to Consolidated Financial Statements

§	decrease in natural gas prices

§	continued collection of $221 million in ERRA Trigger revenue requirement as approved by the CPUC in the first quarter of 2014. The ERRA Trigger rate increase was effective on April 1, 2014 and continued through December 31, 2015.

In December 2015, the CPUC approved SDG&E’s 2016 ERRA revenue requirement of $1.3 billion, an increase of $43 million from its 2015 revenue requirement. As the new revenue requirement is effective on January 1, 2016, management expects the ERRA balance to remain stable in 2016.

SoCalGas and SDG&E use the Core Fixed Cost Account (CFCA) balancing account to record the difference between the authorized margin and other costs allocated to the core market, and the actual revenues billed to customers in rates for recovery of these costs. Because warmer weather experienced last year and through the current year resulted in lower natural gas consumption compared to authorized levels, SoCalGas’ CFCA balance was undercollected by $328 million at December 31, 2015 and $266 million at December 31, 2014. SDG&E’s CFCA balance was undercollected by $105 million at December 31, 2015 and $81 million at December 31, 2014.

Under its current ratemaking treatment, SoCalGas and SDG&E have the authority through an Annual Regulatory Account Balance Update filing to recover undercollections accumulated in the prior year, consisting of actual recorded activity through August and an estimate for the remainder of the year. SoCalGas and SDG&E are currently amortizing $125 million and $50 million, respectively, of the December 31, 2014 CFCA balance in 2015 rates. In December 2015, the CPUC approved SoCalGas’ and SDG&E’s recovery of their projected December 31, 2015 CFCA undercollected balances of $417 million and $99 million, respectively, along with other regulatory account balances, in rates effective on January 1, 2016.

Sempra South American Utilities

We expect projects and loans to affiliates at Chilquinta Energía and Luz del Sur to be funded by available funds, funds internally generated by those businesses and by external borrowings. At December 31, 2015 and 2014, Chilquinta Energía had outstanding loans of $72 million and $41 million, respectively, to an affiliate to finance development projects. We discuss these transactions in Note 1 of the Notes to Consolidated Financial Statements.

Sempra Mexico

We expect projects, joint venture investments and dividends in Mexico to be funded through a combination of available funds, including credit facilities, funds internally generated by the Mexico businesses, securities issuances, project financing, interim funding from the parent, and partnering in joint ventures. We discuss IEnova’s potential acquisition of PEMEX’s 50-percent interest in GdC in Note 3 of the Notes to Consolidated Financial Statements.

Sempra Mexico may also generate cash from the sale of its 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As we discuss in Note 18 of the Notes to Consolidated Financial Statements, in February 2016, management approved a plan to market and sell the plant, which had a book value of $262 million at December 31, 2015.

At December 31, 2015 and 2014, Sempra Mexico had outstanding loans of $111 million and $147 million, respectively, to affiliates to finance development projects. We discuss these transactions in Note 1 of the Notes to Consolidated Financial Statements.

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, partnering in joint ventures, and other forms of equity sales. The Sempra Renewables projects have planned in-service dates through 2016.

Sempra Natural Gas

We expect Sempra Natural Gas to require funding for the development and expansion of its portfolio of projects, which may be financed through a combination of operating cash flow, funding from the parent and project financing. In April 2015, Sempra Natural Gas invested $113 million in Rockies Express to repay project debt that matured in early 2015.

In April 2015, Sempra Natural Gas sold the remaining 625-MW block of the Mesquite Power plant, together with a related power sales contract, and received net cash proceeds of $347 million. The sale proceeds were used to pay down commercial paper at Sempra Energy. We discuss this sale further in Note 3 of the Notes to Consolidated Financial Statements.

In December 2015, Sempra Natural Gas redeemed, prior to maturity, $55 million of industrial development bonds payable at Bay Gas Storage Company, Ltd. (Bay Gas).

Sempra Natural Gas, through Cameron LNG JV, is developing a natural gas liquefaction export facility at the Cameron LNG JV terminal. The majority of the three-train liquefaction project is project-financed, with most or all of the remainder of the capital requirements to be provided by the project partners, including Sempra Energy, through equity contributions under a joint venture agreement. We expect that our remaining equity requirements to complete the project will be met by a combination of our share of cash generated from each liquefaction train as it comes on line and additional cash contributions. Under the financing agreements, Sempra Energy signed completion guarantees for 50.2 percent of the debt, which corresponds to $3.7 billion of the total $7.4 billion principal amount of the debt committed under the financing agreements. The project financing and completion guarantees became effective on October 1, 2014, the effective date of the joint venture formation. The completion guarantees will terminate upon satisfaction of certain conditions, including all three trains achieving commercial operation and meeting certain operational performance tests. The completion guarantees are anticipated to be terminated in the second half of 2019.

We discuss Cameron LNG JV and the joint venture financing further in Notes 3 and 4 of the Notes to Consolidated Financial Statements.

CASH FLOWS FROM OPERATING ACTIVITIES

CASH PROVIDED BY OPERATING ACTIVITIES
(Dollars in millions)
	2015			2015 change					2014			2014 change					2013
Sempra Energy Consolidated		$	2,905		$	744	34	%		$	2,161		$	377	21	%		$	1,784
SDG&E			1,664			567	52				1,097			378	53				719
SoCalGas			880			115	15				765			84	12				681

Sempra Energy Consolidated

Cash provided by operating activities at Sempra Energy increased in 2015 primarily due to:

$544 million net decrease in net undercollected regulatory balancing accounts in 2015 at the California Utilities (including long-term amounts included in regulatory assets) compared to a $277 million net increase in 2014. 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 discussion of changes in regulatory balances at both SDG&E and SoCalGas below;

§	$245 million higher net income, adjusted for noncash items included in earnings, in 2015 compared to 2014, primarily due to improved operations at the California Utilities, as well as higher pipeline earnings at Sempra Mexico, as we discuss in “Results of Operations” above;

$65 million decrease in inventories in 2015 compared to a $133 million increase in 2014, primarily due to mandated natural gas withdrawals, as well as lower volume added to storage at SoCalGas in 2015 as a result of a moratorium on natural gas injections at its Aliso Canyon natural gas storage facility; and

§	$126 million decrease in settlement payments and associated legal fees for wildfire claims at SDG&E in 2015 compared to 2014; offset by

§	$157 million decrease in accounts payable in 2015 compared to a $109 million increase in 2014, primarily due to lower average cost of natural gas purchased at SoCalGas, as well as the moratorium on natural gas injections at its Aliso Canyon storage facility;

§	$179 million in purchases of greenhouse gas allowances ($117 million at SDG&E and $62 million at SoCalGas);

§	$99 million increase in accounts receivable in 2015 compared to a $44 million decrease in 2014. The 2015 increase was primarily due to an increase in physical gas sales at SoCalGas; and

$325 million receivable for expected insurance recovery of certain expenditures related to the natural gas leak at the Aliso Canyon storage facility, and $274 million reserve for accrued expenditures expected to be paid in 2016 related to the leak. We discuss the Aliso Canyon leak further in Note 15 of the Notes to Consolidated Financial Statements, in “Factors Influencing Future Performance” below and in “Risk Factors” in our 2015 Annual Report on Form 10-K.

Cash provided by operating activities at Sempra Energy increased in 2014 compared to 2013 primarily due to:

§	$277 million increase in net undercollected regulatory balancing accounts in 2014 at the California Utilities (including long-term amounts included in regulatory assets) compared to a $411 million increase in 2013;

$44 million decrease in accounts receivable in 2014 compared to a $273 million increase in 2013; the change was mainly due to a $30 million decrease at SoCalGas in 2014 compared to a $113 million increase in 2013, primarily due to a decrease in physical gas sales in December 2014 compared to December 2013, and a $39 million decrease in natural gas sales at Sempra Natural Gas in 2014 compared to a $69 million increase in 2013;

§	$109 million increase in accounts payable in 2014 compared to a $28 million decrease in 2013, mainly due to an increase in 2014 related to natural gas purchased at SoCalGas; and

§	$82 million decrease in settlement payments and associated legal fees for wildfire claims at SDG&E in 2014 compared to 2013; offset by

§	$133 million increase in inventory in 2014 compared to a $116 million decrease in 2013; the 2014 increase was mainly due to a $113 million increase at SoCalGas, primarily due to higher natural gas storage volume; and

§	$86 million lower net income, adjusted for noncash items included in earnings, in 2014.

SDG&E

Cash provided by operating activities at SDG&E increased in 2015 primarily due to:

§	$474 million decrease in net undercollected regulatory balancing accounts in 2015 compared to a $47 million increase in 2014 (including long-term amounts included in regulatory assets in 2014). The 2015 decrease was primarily associated with the electric commodity accounts;

§	$126 million decrease in settlement payments and associated legal fees for wildfire claims in 2015 compared to 2014; and

§	$102 million higher net income, adjusted for noncash items included in earnings, in 2015 compared to 2014, primarily due to improved operations; offset by

§	$117 million in purchases of greenhouse gas allowances in 2015; and

§	$88 million income tax payments, net of income tax refunds, in 2015 due to full utilization of net operating losses carried forward in 2015.

Cash provided by operating activities at SDG&E increased in 2014 compared to 2013 primarily due to:

§	$47 million increase in net undercollected regulatory balancing accounts in 2014 (including long-term amounts included in regulatory assets) compared to a $301 million increase in 2013; and

§	$82 million decrease in settlement payments and associated legal fees for wildfire claims in 2014 compared to 2013.

SoCalGas

Cash provided by operating activities at SoCalGas increased in 2015 primarily due to:

$70 million decrease in net undercollected regulatory balancing accounts in 2015 (including long-term amounts included in regulatory assets) compared to a $230 million decrease in net overcollected regulatory balancing accounts in 2014, primarily due to changes associated with the fixed cost balancing accounts;

§	$102 million decrease in inventories in 2015 compared to a $113 million increase in 2014, primarily due to mandated natural gas withdrawals, as well as lower volume added to storage in 2015 as a result of a moratorium on natural gas injections at the Aliso Canyon natural gas storage facility; and

§	$110 million higher net income, adjusted for noncash items included in earnings, in 2015 compared to 2014, primarily due to improved operations; offset by

§	$143 million decrease in accounts payable in 2015 compared to a $156 million increase in 2014, primarily due to lower average cost of natural gas purchased, as well as the moratorium on natural gas injections at its Aliso Canyon facility;

§	$90 million increase in accounts receivable in 2015 compared to a $30 million decrease in 2014. The increase in 2015 was primarily due to an increase in physical gas sales in 2015;

§	$62 million in purchases of greenhouse gas allowances in 2015; and

§	$325 million receivable for expected insurance recovery of certain expenditures related to the natural gas leak at the Aliso Canyon storage facility, and $274 million reserve for accrued expenditures expected to be paid in 2016 related to the leak.

Cash provided by operating activities at SoCalGas increased in 2014 compared to 2013 primarily due to:

§	$156 million increase in accounts payable in 2014 compared to a $54 million decrease in 2013, primarily due to a $75 million increase in natural gas purchases in 2014 compared to a $65 million decrease in 2013;

§	$30 million decrease in accounts receivable in 2014 compared to a $113 million increase in 2013, primarily due to a decrease in physical gas sales in December 2014 compared to December 2013; and

§	$27 million higher net income, adjusted for noncash items included in earnings, in 2014 compared to 2013; offset by

§	$230 million decrease in net overcollected regulatory balancing accounts in 2014 (including long-term amounts included in regulatory assets) compared to $110 million decrease in 2013; and

$113 million increase in inventory in 2014 compared to an $82 million decrease in 2013, primarily due to higher volume of natural gas added to storage in 2014 compared to 2013 as a result of colder than normal weather in the fourth quarter of 2013, which left a lower volume of natural gas in storage at the end of 2013 compared to the end of 2012, combined with higher gas prices in 2014.

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
(Dollars in millions)
	Pension benefits									Other postretirement benefits
	2015			2014			2013			2015			2014			2013
Sempra Energy Consolidated		$	33		$	128		$	133		$	11		$	16		$	27
SDG&E			2			56			51			7			14			14
SoCalGas			6			39			59			1			―			9

The passage of the Highway and Transportation Funding Act of 2014 decreased the minimum contributions required for single employer defined benefit plans for 2014 and future years, impacting each of the domestic pension plans.

We discuss pension and other postretirement benefit plans further in Note 7 of the Notes to Consolidated Financial Statements.

CASH FLOWS FROM INVESTING ACTIVITIES

CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
	2015				2015 change						2014				2014 change					2013
Sempra Energy Consolidated		$	(2,885	)		$	(457	)	(14	)%		$	(3,342	)		$	1,653	98	%		$	(1,689	)
SDG&E			(1,086	)			(40	)	(4	)			(1,126	)			153	16				(973	)
SoCalGas			(1,402	)			298		27				(1,104	)			376	52				(728	)

Sempra Energy Consolidated

Cash used in investing activities at Sempra Energy decreased in 2015 primarily due to:

§	$347 million of net proceeds received from Sempra Natural Gas’ sale of the remaining 625-MW block of its Mesquite Power plant and a related power sale contract in 2015;

§	$43 million net decrease in advances to unconsolidated affiliates in 2015 compared to $167 million net increase in advances in 2014;

§	$60 million decrease in Nuclear Decommissioning Trust assets at SDG&E in 2015 due to withdrawals for SONGS decommissioning costs incurred in 2013 and 2014. We discuss the Nuclear Decommissioning Trusts further in Note 13 of the Notes to Consolidated Financial Statements; and

§	$26 million proceeds received from Sempra Renewables’ sale of the Rosamond Solar development project; offset by

§	in 2014, $148 million cash proceeds, net of cash sold, from Sempra Renewables’ sale of 50-percent equity interests in Copper Mountain Solar 3 ($66 million) and Broken Bow 2 Wind ($58 million), and Sempra Mexico’s sale of a 50-percent equity interest in Energía Sierra Juárez ($24 million); and

§	$33 million higher capital expenditures in 2015.

Cash used in investing activities at Sempra Energy increased in 2014 compared to 2013 primarily due to:

§	$551 million increase in capital expenditures;

§	$371 million of proceeds received in 2013 from Sempra Natural Gas’ sale of the first block of its Mesquite Power plant;

§	$214 million invested in Sempra Renewables’ joint venture partnerships in 2014;

§	$238 million U.S. Treasury grant proceeds received in 2013;

§	$153 million higher increase in net advances to affiliates in 2014; and

§	$50 million distribution in 2013 from RBS Sempra Commodities LLP (RBS Sempra Commodities).

SDG&E

Cash used in investing activities at SDG&E decreased in 2015 due to:

§	$60 million decrease in Nuclear Decommissioning Trust assets in 2015 as a result of CPUC authorization to access trust funds for SONGS decommissioning costs incurred in 2013 and 2014; and

§	$30 million expenditures related to a long-term service agreement in 2014; offset by

§	$33 million increase in capital expenditures.

Cash used in investing activities at SDG&E increased in 2014 compared to 2013 primarily due to a $122 million increase in capital expenditures.

SoCalGas

Cash used in investing activities at SoCalGas increased in 2015 due to:

§	$248 million increase in capital expenditures; and

§	$50 million increase in net advances to Sempra Energy in 2015.

Cash used in investing activities at SoCalGas increased in 2014 compared to 2013 due to:

§	$342 million increase in capital expenditures; and

§	$34 million decrease in net advances to Sempra Energy in 2013.

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
2015		$	3,156		$	200
2014			3,123			240
2013			2,572			22
2012			2,956			445
2011			2,844			941

California Utilities

The California Utilities’ capital expenditures for property, plant and equipment were

(Dollars in millions)	2015		2014		2013
SDG&E	$	1,133	$	1,100	$	978
SoCalGas		1,352		1,104		762

Capital expenditures at the California Utilities in 2015 consisted primarily of:

SDG&E

§	$737 million for improvements to natural gas, including pipeline safety, and electric generation and distribution systems

§	$396 million for improvements to electric transmission systems

SoCalGas

§	$1.1 billion for improvements to distribution, transmission and storage systems, and for pipeline safety, including $361 million for the Pipeline Safety Enhancement Plan (PSEP)

§	$206 million for advanced metering infrastructure

§	$12 million for other natural gas projects

Sempra International and Sempra U.S. Gas & Power

Sempra South American Utilities

Sempra South American Utilities had capital expenditures of $154 million in 2015, $174 million in 2014 and $200 million in 2013, primarily related to improvements to electric transmission and distribution systems and generation projects, including Santa Teresa, a 100-MW hydroelectric power plant in Peru that began commercial operations in September 2015.

Sempra Mexico

Sempra Mexico had capital expenditures of $302 million in 2015, including $278 million for the development of the Sonora, Ojinaga and San Isidro – Samalayuca pipeline projects, all developed solely by Sempra Mexico. Total capital expenditures in 2014 and 2013 were $325 million and $371 million, respectively, primarily for the development of wind and natural gas pipeline projects.

Sempra Renewables

Capital expenditures of $81 million at Sempra Renewables included construction costs for wind and solar projects while wholly owned as follows:

In 2015:

§	$33 million for construction of Mesquite Solar 3

§	$23 million for construction of Copper Mountain Solar 4

§	$14 million for construction of the Black Oak Getty wind project

§	$6 million for construction of Mesquite Solar 2

In 2014:

§	$114 million for construction of Broken Bow 2 Wind

§	$74 million for construction of Copper Mountain Solar 3

In 2013:

§	$93 million for Copper Mountain Solar 3

§	$46 million for Mesquite Solar 1

§	$26 million for Broken Bow 2 Wind

§	$9 million for Copper Mountain Solar 2

Sempra Natural Gas

In 2015, 2014 and 2013, Sempra Natural Gas had $86 million, $212 million and $83 million, respectively, of capital expenditures, including:

§	$55 million for development of the Cameron Interstate Pipeline and other LNG liquefaction development costs, and $7 million for additional capacity at Bay Gas in 2015

§	$135 million for Cameron LNG terminal and liquefaction project before formation of Cameron LNG JV, and $58 million for additional capacity at Bay Gas and Mississippi Hub in 2014

§	$36 million for Cameron LNG terminal and liquefaction project, and $29 million for development of approximately 13 Bcf of additional capacity at Bay Gas and Mississippi Hub in 2013

Parent and Other

In 2015 and 2014, Parent and Other had capital expenditures of $46 million and $16 million, respectively. Expenditures in 2015 were primarily related to the build-to-suit lease for Sempra Energy’s new headquarters.

Sempra Energy Consolidated Investments and Acquisitions

During the years ended December 31, 2015, 2014 and 2013, Sempra Energy made investments in various joint ventures and other businesses, summarized in the following table.

EXPENDITURES FOR INVESTMENTS AND ACQUISITION OF BUSINESSES(1)
(Dollars in millions)
	Years ended December 31,
	2015		2014		2013
Sempra Renewables:
Auwahi Wind	$	―	$	―	$	1
Black Oak Getty Wind(2)		3		―		―
Broken Bow 2 Wind		―		―		11
California solar partnership		―		121		―
Copper Mountain Solar 2		―		3		―
Copper Mountain Solar 3		5		86		―
Flat Ridge 2 Wind		3		―		4
Mehoopany Wind		13		4		1
Sempra Natural Gas:
Cameron LNG JV(3)		59		18		―
Mississippi Hub LLC(4)		2		―		3
Rockies Express Pipeline LLC(5)		113		―		―
Willmut Gas Company		―		―		2
Parent and other		2		8		―
Total	$	200	$	240	$	22
(1) Net of cash acquired.
(2) Excludes accrued purchase price of $5 million.
(3) Includes capitalized interest of $49 million and $12 million in 2015 and 2014, respectively, on Sempra Natural Gas' investment, as the joint venture has not commenced planned principal operations.
(4) Investment in industrial development bonds.
(5) Repayment of project debt that matured in early 2015.

Sempra Energy Consolidated Distributions From Investments

Sempra Energy’s Distributions From Investments in 2015, 2014 and 2013 are primarily the return of investment from equity method and other investments at Sempra Renewables and Sempra Natural Gas. Distributions of earnings from equity method investments, which are not included in the table below, represent return on the investments and are included in cash flows from operations.

During the years ended December 31, 2015, 2014 and 2013, Sempra Energy received distributions from investments in various joint ventures and other investments as summarized by segment in the following table.

DISTRIBUTIONS FROM INVESTMENTS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Sempra Renewables(1)		$	15		$	11		$	67
Sempra Natural Gas(2)			―			―			31
Parent and other(3)			―			2			54
Total		$	15		$	13		$	152

(1) Distributions in 2013 include $15 million related to U.S. Treasury grant proceeds received at the Auwahi Wind joint venture.
(2) Distributions at Sempra Natural Gas in 2013 were from Rockies Express.
(3) Distributions in 2013 include $50 million from RBS Sempra Commodities LLP.

FUTURE CONSTRUCTION EXPENDITURES AND INVESTMENTS

The amounts and timing of capital expenditures are generally subject to approvals by various regulatory and other governmental and environmental bodies, including the CPUC and the FERC. However, in 2016, we expect to make capital expenditures and investments of approximately $5.1 billion. These expenditures include

$2.7 billion at the California Utilities for capital projects and plant improvements ($1.3 billion at SDG&E and $1.4 billion at SoCalGas), excluding incremental amounts that may result from the natural gas leak at the Aliso Canyon facility or the related increased requirements for all natural gas storage facilities

§	$2.4 billion at our other subsidiaries for acquisition of our joint venture partner’s 50-percent interest in GdC, capital projects in Mexico and South America, and development of LNG, natural gas and renewable generation projects

The California Utilities’ 2016 planned capital expenditures and investments include

SDG&E

§	$800 million for improvements to natural gas, including pipeline safety, and electric generation and distribution systems

§	$500 million for improvements to electric transmission systems

SoCalGas

§	$1.2 billion for improvements to distribution, transmission and storage systems, and for pipeline safety, including $350 million for the PSEP

§	$100 million for advanced metering infrastructure

§	$100 million for other natural gas projects

The California Utilities expect to finance these expenditures and investments with cash flows from operations and debt issuances.

Over the next five years, 2016 through 2020, and subject to a number of factors including those described below which could cause these estimates to vary substantially, the California Utilities expect to make capital expenditures and investments of:

§	$6 billion at SDG&E

§	$5.9 billion at SoCalGas

In 2016, the expected capital expenditures and investments of approximately $2.4 billion (excluding amounts expended by joint ventures and net of anticipated project financing and joint venture structures as noted below) at our other subsidiaries include

Sempra South American Utilities

§	approximately $220 million for capital projects in South America (approximately $160 million and $60 million in Peru and Chile, respectively), primarily related to improvements to electric transmission and distribution systems

Sempra Mexico

§	approximately $450 million to $500 million for capital projects, including approximately $400 million for the development of the Sonora, Ojinaga and San Isidro – Samalayuca pipeline projects, all developed solely by Sempra Mexico

§	funds for the acquisition of our joint venture partner’s 50-percent interest in GdC, as we discuss in Note 3 of the Notes to Consolidated Financial Statements.

Sempra Renewables

§	approximately $400 million (net of financing and partnership structures) for the development of wind and solar renewable projects, including Black Oak Getty Wind, Mesquite Solar 2, Mesquite Solar 3 and Copper Mountain Solar 4

Sempra Natural Gas

§	approximately $250 million for development of LNG and natural gas transportation projects, including

□	approximately $80 million equity investment in Rockies Express

□	approximately $50 million capitalized interest on our investment in the Cameron LNG JV, and $80 million for development of the Cameron Interstate Pipeline

Over the next five years, 2016 through 2020, and subject to the factors described below which could cause these estimates to vary substantially, Sempra Energy expects to make aggregate capital expenditures of approximately $3.8 billion at its subsidiaries other than the California Utilities.

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. At Sempra Mexico and Sempra Natural Gas, the amounts also exclude 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 13, 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 investment-grade credit ratings and capital structure.

CASH FLOWS FROM FINANCING ACTIVITIES

CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
	2015				2015 change				2014			2014 change				2013
Sempra Energy Consolidated		$	(173	)		$	(1,027	)		$	854		$	516			$	338
SDG&E			(566	)			(576	)			10			(184	)			194
SoCalGas			495				98				397			406				(9	)

Sempra Energy Consolidated

Financing activities at Sempra Energy were a net use of cash in 2015 compared to a net source of cash in 2014, primarily due to:

§	$622 million net decrease in short-term debt in 2015 compared to a $412 million net increase in 2014; and

$280 million lower issuances of debt, including a decrease in commercial paper and other short-term debt borrowings with maturities greater than 90 days of $630 million (issuances of $633 million in 2015 compared to $1.3 billion in 2014), offset by higher issuances of long-term debt of $350 million (issuances of $2.4 billion in 2015 compared to $2 billion in 2014); offset by

$180 million lower payments on debt, including lower payments of long-term debt of $467 million (payments of $736 million in 2015 compared to $1.2 billion in 2014), offset by higher payments of commercial paper and other short-term debt with maturities greater than 90 days of $287 million (payments of $1.1 billion in 2015 compared to $831 million in 2014);

§	$74 million purchase of noncontrolling interests in 2014; and

§	$52 million tax benefit related to share-based compensation in 2015 (see additional discussion in Note 6 of the Notes to Consolidated Financial Statements).

Cash provided by financing activities at Sempra Energy increased in 2014 compared to 2013 primarily due to:

$1.2 billion higher issuances of debt, including an increase in issuances of long-term debt of $373 million ($2 billion in 2014 compared to $1.6 billion in 2013) and an increase in commercial paper and other short-term debt with maturities greater than 90 days of $818 million ($1.3 billion increase in 2014 compared to $445 million in 2013); and

§	$412 million net increase in short-term debt in 2014 compared to $256 million in 2013; offset by

§	$574 million net proceeds received in 2013 from the sale of noncontrolling interests at Sempra Mexico; and

$246 million higher payments on debt, including higher payments of long-term debt of $219 million ($1.2 billion in 2014 compared to $984 million in 2013), and higher payments of commercial paper and other short-term debt with maturities greater than 90 days of $27 million ($831 million in 2014 compared to $804 million in 2013).

SDG&E

At SDG&E, financing activities were a net use of cash in 2015 compared to a net source of cash in 2014, primarily due to:

§	$523 million higher payments on long-term debt in 2015;

§	$131 million net decrease in short-term debt in 2015 compared to a $187 million net increase in 2014; and

§	$100 million increase in common stock dividends paid ($300 million in 2015 compared to $200 million in 2014); offset by

§	$344 million higher issuances of debt with maturities greater than 90 days in 2015.

Cash provided by financing activities at SDG&E decreased in 2014 compared to 2013 primarily due to:

§	$350 million lower issuance of long-term debt; and

§	$200 million common stock dividends paid in 2014; offset by

§	$175 million lower payments on long-term debt; and

§	$128 million higher net increase in short-term debt.

SoCalGas

Cash provided by financing activities at SoCalGas increased in 2015 primarily due to:

§	$250 million payments of long-term debt in 2014; and

§	$50 million lower common stock dividends paid in 2015; offset by

§	$148 million lower issuances of long-term debt in 2015; and

§	$50 million net decrease in short-term debt in 2015 compared to an $8 million net increase in 2014.

At SoCalGas, financing activities were a net source of cash in 2014 compared to a net use of cash in 2013, primarily due to:

§	$747 million net proceeds from the issuance of long-term debt in 2014; offset by

§	$250 million payment of long-term debt in 2014;

§	$50 million increase in common stock dividends paid ($100 million in 2014 compared to $50 million in 2013); and

§	$34 million lower net increase in short-term debt.

LONG-TERM DEBT

Long-term debt balances at December 31 were

LONG-TERM DEBT(1)
(Dollars in millions)
	At December 31,
	2015			2014(2)			2013(2)
Sempra Energy Consolidated		$	14,041		$	12,555		$	12,321
SDG&E			4,505			4,648			4,514
SoCalGas			2,490			1,891			1,402

(1) Includes current portion of long-term debt.
(2) As adjusted for the retrospective adoption of Accounting Standards Update (ASU) 2015-03, as we discuss in Note 2 of the Notes to Consolidated Financial Statements.

At December 31, 2015, the following information applies to long-term debt:

	Sempra Energy
	Consolidated		SDG&E		SoCalGas
Weighted average life to maturity, in years	11.1		15.3		15.0
Weighted average interest rate	4.44	%	4.37	%	3.94	%

Issuances of Long-Term Debt

Major public issuances of long-term debt over the last three years include the following:

ISSUANCES OF LONG-TERM DEBT
(Dollars in millions)
	Amount at issuance		Rate			Maturing

Sempra Energy:
Notes, November 2015	$	400		2.85	%		2020
Notes, November 2015		350		3.75			2025
Notes, March 2015		500		2.40			2020
Notes, June 2014		500		3.55			2024
Notes, November 2013		500		4.05			2023

Sempra Mexico:
Notes, February 2013		100		2.66			2018
Notes, February 2013		298		4.12			2023

SDG&E:
First mortgage bonds at variable rates (0.48% at December 31, 2015),
March 2015		140		0.48			2017
First mortgage bonds, March 2015		250		1.914			2022
366-day commercial paper, May 2014		100		0.40			2015
First mortgage bonds, September 2013		450		3.60			2023

SoCalGas:
First mortgage bonds, June 2015		250		1.55			2018
First mortgage bonds, June 2015		350		3.20			2025
First mortgage bonds, September 2014		500		3.15			2024
First mortgage bonds, March 2014		250		4.45			2044

Sempra Energy used the proceeds from its issuances of long-term debt primarily for general corporate purposes and to repay commercial paper. We discuss issuances of long-term debt further in Note 5 of the Notes to Consolidated Financial Statements.

The California Utilities used the proceeds from their issuances of long-term debt:

§	for general working capital purposes;

§	to support their electric (at SDG&E) and natural gas (SDG&E and SoCalGas) procurement programs;

§	to repay commercial paper at SDG&E and SoCalGas; 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 2015 included

§	$250 million of SDG&E’s 5.3-percent first mortgage bonds due in 2015

§	$169 million early redemption of SDG&E’s 4.9-percent to 5.5-percent debt instruments maturing between 2021 and 2027

§	$100 million of SDG&E’s 366-day commercial paper due in 2015

§	$55 million early redemption of Bay Gas’ variable-rate industrial development bonds due in 2037

§	$51 million of Sempra Mexico’s variable-rate notes due in 2017

§	$18 million of SDG&E’s 1.914-percent amortizing first mortgage bonds due in 2022

Payments on long-term debt in 2014 included

§	$500 million of Sempra Energy’s 2-percent notes due in 2014

§	$300 million of Sempra Energy’s notes at variable rates due in 2014

§	$250 million of SoCalGas’ 5.5-percent notes due in 2014

§	$62 million of 5.1-percent to 6.75-percent Luz del Sur bank loans maturing in 2015 and 2016

§	$54 million of 5.72-percent to 6.47-percent Series A Luz del Sur notes maturing in 2014

Payments on long-term debt in 2013 included

§	$400 million of Sempra Energy’s 6-percent notes due in 2013

§	$250 million of Sempra Energy’s 8.9-percent notes due in 2013, including $200 million at variable rates after fixed-to-floating interest rate swaps

§	$60 million of SDG&E’s 5.85-percent Pollution Control Revenue Bonds (PCRBs) due in 2021

§	$115 million of SDG&E’s 5.9-percent PCRBs due in 2014

§	$14 million of SDG&E’s 6.8-percent PCRBs due in 2015

§	$86 million of 2.75-percent Series A Chilean public bonds maturing in 2014

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

§	$52 million in 2015

§	$56 million in 2014

§	$62 million in 2013

SDG&E

In 2013, SDG&E redeemed all of its outstanding preferred stock for $83 million (including call premium and accrued dividends). We discuss the redemption in Note 11 of the Notes to Consolidated Financial Statements.

DIVIDENDS

Sempra Energy

Sempra Energy paid cash dividends on common stock of:

§	$628 million in 2015

§	$598 million in 2014

§	$606 million in 2013

In 2015, dividends declared increased due to an increase in the per-share quarterly dividend from $0.66 in 2014 to $0.70 in 2015.

In 2014, dividends declared increased due to an increase in the per-share quarterly dividend from $0.63 in 2013 to $0.66 in 2014. Offsetting this increase was a decrease in cash paid to fund dividends in 2014 compared to 2013 due to the issuance of new common shares to fund the dividend requirements of our savings plans and common stock purchase plan.

On December 15, 2015, Sempra Energy declared a quarterly dividend of $0.70 per share of common stock that was paid on January 15, 2016. We provide additional information about Sempra Energy dividends above in “Capital Resources and Liquidity – Overview – Sempra Energy Consolidated.”

SDG&E

In 2015 and 2014, SDG&E paid dividends to Enova Corporation (Enova) and Enova paid corresponding dividends to Sempra Energy of $300 million and $200 million, respectively. SDG&E did not pay any common dividends in 2013 to preserve cash to fund its capital expenditures program, which included the Sunrise Powerlink.

Enova, a wholly owned subsidiary of Sempra Energy, owns all of SDG&E’s outstanding common stock. Accordingly, dividends paid by SDG&E to Enova and dividends paid by Enova to Sempra Energy are both eliminated in Sempra Energy’s Consolidated Financial Statements.

SoCalGas

SoCalGas paid dividends to Pacific Enterprises (PE) and PE paid corresponding dividends to Sempra Energy of:

§	$50 million in 2015

§	$100 million in 2014

§	$50 million in 2013

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.

DIVIDEND RESTRICTIONS

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, 2015, based upon these regulations, Sempra Energy could have received combined loans and dividends of approximately $600 million, funded by long-term debt issuance, from SDG&E and approximately $447 million from SoCalGas.

We provide additional information about restricted net assets in Note 1 of the Notes to Consolidated Financial Statements.

CAPITALIZATION

Our debt to capitalization ratio, calculated as total debt as a percentage of total debt and equity, was as follows:

TOTAL CAPITALIZATION AND DEBT-TO-CAPITALIZATION RATIOS(1)
(Dollars in millions)
	December 31, 2015
	Sempra Energy
	Consolidated(2)				SDG&E(2)				SoCalGas
Total capitalization		$	27,242			$	9,949			$	5,639
Debt-to-capitalization ratio			54	%			47	%			44	%

	December 31, 2014
	Sempra Energy
	Consolidated(2)				SDG&E(2)				SoCalGas
Total capitalization		$	26,388			$	9,886			$	4,722
Debt-to-capitalization ratio			54	%			50	%			41	%

(1)	As adjusted for the retrospective adoption of Accounting Standards Update 2015-03, as we discuss in Note 2 of the Notes to Consolidated Financial Statements
(2)	Includes noncontrolling interest and debt of Otay Mesa Energy Center LLC with no significant impact.

Significant changes during 2015 that affected capitalization include the following:

§	Sempra Energy Consolidated: comprehensive income exceeding dividends, partially offset by a net increase in debt

§	SDG&E: comprehensive income exceeding dividends and decrease in both long-term and short-term debt

§	SoCalGas: primarily an increase in long-term debt, partially offset by comprehensive income exceeding dividends

We provide additional information about these significant changes in Notes 1 and 5 of the Notes to Consolidated Financial Statements.

COMMITMENTS

The following tables summarize principal contractual commitments, primarily long-term, at December 31, 2015 for Sempra Energy Consolidated, SDG&E and SoCalGas. We provide additional information about commitments above and in Notes 5, 7, 13 and 15 of the Notes to Consolidated Financial Statements.

PRINCIPAL CONTRACTUAL COMMITMENTS OF SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	2016		2017 and 2018		2019 and 2020		Thereafter		Total
Long-term debt	$	897	$	2,223	$	1,822	$	8,821	$	13,763
Interest on long-term debt(1)		592		1,073		849		4,727		7,241
Operating leases		71		134		107		283		595
Capital leases(2)		7		21		26		697		751
Purchased-power contracts		741		1,507		1,496		7,169		10,913
Natural gas contracts		358		647		206		199		1,410
LNG contract(3)		330		888		1,021		5,524		7,763
Construction commitments		1,174		65		22		10		1,271
Build-to-suit lease		10		20		21		256		307
SONGS decommissioning		96		119		140		312		667
Sunrise Powerlink wildfire mitigation fund		3		6		6		102		117
Other asset retirement obligations		33		74		65		1,416		1,588
Pension and other postretirement benefit
obligations(4)		131		428		475		1,164		2,198
Environmental commitments(5)		25		19		3		12		59
Other		98		27		18		45		188
Total	$	4,566	$	7,251	$	6,277	$	30,737	$	48,831

(1	)	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, 2015.
(2	)	Of the present value of the net minimum lease payments, $500 million will be recorded as a capital lease obligation when construction of the peaker plant facility is completed and delivery of contracted power commences, which is scheduled to occur in June 2017.
(3	)	Sempra Natural Gas has a purchase agreement with a major international company for the supply of LNG to the Energía Costa Azul terminal. The multi-year agreement is priced using a predetermined formula based on natural gas market indices. The expected payments under the contract are based on forward prices of the applicable market index from 2016 to 2025 and an estimated one percent escalation per year beyond 2025 through contract termination in 2029. We provide more information about this contract in Note 15 of the Notes to Consolidated Financial Statements.
(4	)	Amounts represent expected company contributions to the plans for the next 10 years.
(5	)	Excludes amounts related to the natural gas leak at SoCalGas' Aliso Canyon natural gas storage facility.

PRINCIPAL CONTRACTUAL COMMITMENTS OF SDG&E
(Dollars in millions)
	2016		2017 and 2018		2019 and 2020		Thereafter		Total
Long-term debt	$	46	$	393	$	356	$	3,509	$	4,304
Interest on long-term debt(1)		189		374		340		2,277		3,180
Operating leases		25		44		34		70		173
Capital leases(2)		5		19		26		694		744
Purchased-power contracts		521		1,006		923		6,071		8,521
Construction commitments		67		58		22		10		157
SONGS decommissioning		96		119		140		312		667
Sunrise Powerlink wildfire mitigation fund		3		6		6		102		117
Other asset retirement obligations		3		7		7		144		161
Pension and other postretirement benefit
obligations(3)		7		101		110		258		476
Environmental commitments		2		2		2		10		16
Total	$	964	$	2,129	$	1,966	$	13,457	$	18,516

(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, 2015.
(2)	Of the present value of the net minimum lease payments, $500 million will be recorded as a capital lease obligation when construction of the peaker plant facility is completed and delivery of contracted power commences, which is scheduled to occur in June 2017.
(3)	Amounts represent expected SDG&E contributions to the plans for the next 10 years.

PRINCIPAL CONTRACTUAL COMMITMENTS OF SOCALGAS
(Dollars in millions)
	2016			2017 and 2018			2019 and 2020			Thereafter			Total
Long-term debt		$	8		$	500		$	―		$	2,005		$	2,513
Interest on long-term debt(1)			99			186			162			1,173			1,620
Natural gas contracts			127			208			73			105			513
Operating leases			38			75			61			131			305
Capital leases			1			―			―			―			1
Construction commitments			11			7			―			―			18
Environmental commitments(2)			6			16			1			2			25
Pension and other postretirement benefit
obligations(3)			78			246			284			767			1,375
Asset retirement obligations			29			66			57			1,231			1,383
Total		$	397		$	1,304		$	638		$	5,414		$	7,753

(1)	SoCalGas calculates interest payments using the stated interest rate for fixed-rate obligations.
(2)	Excludes amounts related to the natural gas leak at the Aliso Canyon natural gas storage facility.
(3)	Amounts represent expected SoCalGas 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 at December 31, 2015 of

§	$55 million for Sempra Energy Consolidated

§	$20 million for SDG&E

§	$27 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 6 of the Notes to Consolidated Financial Statements.

OFF-BALANCE SHEET ARRANGEMENTS

The maximum aggregated amount of guarantees provided by Sempra Energy on behalf of related parties at December 31, 2015 is $4.5 billion. We discuss these guarantees in Note 4 of the Notes to Consolidated Financial Statements.

SDG&E has entered into power purchase arrangements which are variable interests. We discuss variable interests in Note 1 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 2015. At December 31, 2015, Sempra Energy’s unsecured debt rating remained at BBB+ with a stable outlook and SDG&E’s and SoCalGas’ unsecured debt rating remained at A1 with a stable outlook.

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 that may be impacted by each borrower’s credit rating.

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 25 basis points, depending on the severity of the downgrade. The commitment fee on available unused credit would also increase 2.5 to 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 9 of the Notes to Consolidated Financial Statements.

FACTORS INFLUENCING FUTURE PERFORMANCE

CALIFORNIA UTILITIES

Overview

The California Utilities’ operations have historically provided relatively stable earnings and liquidity.

The California Utilities’ performance will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by the California legislature 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 Notes 13, 14 and 15 of the Notes to Consolidated Financial Statements.

Joint Matters

CPUC General Rate Case (GRC)

As we discuss further in Note 14 of the Notes to Consolidated Financial Statements, in September 2015, the California Utilities filed settlement agreements with the CPUC that resolve all material matters related to their 2016 GRC proceeding, except for the revenue requirement implications of certain income tax benefits associated with flow-through repair allowance tax deductions, discussed below. The settlement agreements are with eight of eleven intervening parties. For SoCalGas, the settlement proposes a total revenue requirement in 2016 of $2.219 billion, which is $133 million less than its original request. The proposed settlement represents an increase of $122 million or 6 percent over the 2015 total revenue requirement. For SDG&E, the settlement proposes a total revenue requirement in 2016 of $1.811 billion, which is $100 million less than its original request (as revised). The proposed settlement represents an increase of $17 million, or one percent over the 2015 total revenue requirement. The filed settlement agreements also call for attrition adjustments of 3.5 percent for both 2017 and 2018. The California Utilities also filed a separate agreement, reached with the CPUC Office of Ratepayer Advocates (ORA), proposing that a fourth year (2019) be added to the GRC period, with a revenue requirement increase of 4.3 percent over 2018.

The settlement agreements described above exclude a proposal, for both SoCalGas and SDG&E, regarding certain intra-rate case income tax benefits. The proposal recommends that the CPUC adjust SoCalGas’ rate base by $92 million and SDG&E’s rate base by $93 million, and additionally reduce both utilities’ revenue requirements by amounts currently being tracked in tax memorandum accounts for the year 2015. At December 31, 2015, the pretax balances tracked in these memorandum accounts total $74 million for SoCalGas and $39 million for SDG&E. We believe the proposed treatment would violate and contradict long standing rate making and income tax policy, and would represent a material departure from historical practice. If this proposal is adopted, the outcome would reduce the revenue requirement amounts agreed to in the respective settlement agreements described above. SDG&E and SoCalGas do not expect that the prospective reduction to rate base described above would result in an immediate earnings impact if this proposal is adopted. However, if this proposal is adopted, the amounts currently being tracked in the tax memorandum accounts for 2015 could result in a material charge against earnings when the draft decision is received.

We anticipate all matters to be resolved with the final decision of the 2016 GRC. We expect the CPUC to issue a final decision in the proceeding in the second quarter of 2016.

Future Risk-Based GRC

In December 2014, the CPUC issued a decision incorporating a risk-based decision-making framework into all future GRC application filings for major natural gas and electric utilities. The framework is intended to assist the utilities, interested parties and the CPUC in evaluating energy utility proposals for assessing safety risks and utility plans to manage, mitigate and minimize such risks. As a result, there are two new proceedings, the Safety Model Assessment Proceeding (S-MAP) and the Risk Assessment Mitigation Phase (RAMP), both of which will occur prior to filing future GRC applications. In the S-MAP proceeding, the California Utilities will demonstrate the models they use to prioritize and mitigate risks in order for the CPUC to establish guidelines and standards for these models. In the RAMP proceeding, the California Utilities will demonstrate how they assess utility key risks and present proposed mitigation plans. The California Utilities will file their RAMP reports by November 30, 2016.

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 their natural gas pipeline operations and investments. In August 2011, SoCalGas, SDG&E, Pacific Gas and Electric Company (PG&E) and Southwest Gas filed implementation plans with the CPUC to test or replace natural gas transmission pipelines located in populated areas that have not been pressure tested, as we discuss in Note 14 of the Notes to Consolidated Financial Statements. The California Utilities’ total estimated cost for Phase 1 (the 10-year period of 2012 to 2022) of a two-phase plan was $2.1 billion ($1.6 billion for SoCalGas and $500 million for SDG&E). We anticipate that these cost estimates may be updated to reflect the development of more detailed estimates, actual cost experience as portions of the work are completed and changes in scope. 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 were outside the scope of the 2012 GRC proceedings concluded in 2013. Similarly, these costs are not included in our 2016 GRC filings.

In June 2014, the CPUC issued a final decision in the Triennial Cost Allocation Proceeding (TCAP) addressing SDG&E’s and SoCalGas’ Pipeline Safety Enhancement Plan (PSEP) that approved the utilities’ model for implementing PSEP, and established the criteria to determine the amounts related to PSEP that may be recovered from ratepayers and the processes for recovery of such amounts, including providing that such costs are subject to a reasonableness review. As a result of this decision, SoCalGas recorded an after-tax earnings charge of $5 million in 2014 for costs incurred in prior periods that were no longer subject to recovery. After taking the amounts disallowed for recovery into consideration, as of December 31, 2015, SDG&E and SoCalGas have recorded PSEP costs of $10 million and $162 million, respectively, in the CPUC-authorized regulatory account.

In October 2014, SDG&E and SoCalGas filed a petition for modification with the CPUC requesting authority to recover PSEP costs from customers as incurred, subject to refund pending the results of a reasonableness review by the CPUC, instead of in the subsequent year. This request is pending at the CPUC. SDG&E and SoCalGas have filed with the CPUC for recovery of certain PSEP costs incurred through June 11, 2014 of $0.1 million and $26.8 million, respectively. The ORA, The Utility Reform Network (TURN), and the Southern California Generation Coalition (SCGC) have recommended disallowances of certain costs. The ORA’s recommended disallowance would result in an $11.1 million decrease to SoCalGas’ original recovery application of $26.8 million, to $15.7 million. The disallowance recommended by TURN and SCGC would result in a $2.3 million decrease to SoCalGas’ original recovery application of $26.8 million, to $24.5 million. We expect a decision on this application in the first half of 2016.

In July 2014, the ORA and TURN filed a joint application for rehearing of the CPUC’s June 2014 final decision. In March 2015, the CPUC issued a decision denying ORA’s and TURN’s second request for rehearing, but keeping the record open to admit additional evidence on the limited issue of pressure testing pipelines installed between January 1, 1956 and July 1, 1961. The ORA and TURN allege that the CPUC made a legal error in directing that ratepayers, not shareholders, be responsible for the costs associated with testing or replacing transmission pipelines that were installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. In December 2015, the CPUC issued a final decision finding that ratepayers should not bear the costs associated with pressure testing subject pipelines, or, if replaced, ratepayers should bear neither the average cost of pressure testing nor the undepreciated balance of abandoned pipelines. Through December 31, 2015, the after-tax disallowed costs for SoCalGas and SDG&E are $3.2 million and $0.5 million, respectively. In January 2016, SoCalGas and SDG&E jointly filed a request with the CPUC seeking rehearing of its December 2015 decision. A CPUC decision on the rehearing request is expected in 2016.

We provide additional information regarding these rulemaking proceedings and the California Utilities’ PSEP in Note 14 of the Notes to Consolidated Financial Statements.

Safety Enforcement

California Senate Bill (SB) 291, enacted in October 2013, requires the CPUC to develop and implement a safety enforcement program that includes procedures for monitoring, data tracking and analysis, and investigations, as well as delegating citation authority to CPUC staff personnel under the direction of the CPUC Executive Director. In exercising the citation authority, the CPUC staff will take into account voluntary reporting of potential violations, voluntary resolution efforts undertaken, prior history of violations, the gravity of the violation, and the degree of culpability. In December 2014, the CPUC adopted an electric safety enforcement program whereby electric utilities may be cited by CPUC staff for violations of the CPUC’s safety requirements or federal standards.

In December 2011, the CPUC adopted a gas safety citation program whereby natural gas distribution companies can be cited by CPUC staff for violations of the CPUC’s safety standards. In September 2013, the CPUC’s safety and enforcement division issued its Standard Operating Procedures setting forth its principles and management process for the natural gas safety citation program.

Under each enforcement program, each day of an ongoing violation may be counted as an additional offense. The maximum penalty is $50,000 per offense. Citations under either program may be appealed to the CPUC. The CPUC plans to make further refinements to the electric and gas safety enforcement programs.

SDG&E Matters

2007 Wildfire Litigation

In regard to the 2007 wildfire litigation, SDG&E’s payments for claims settlements plus funds estimated to be required for settlement of outstanding claims and legal fees have exceeded its liability insurance coverage and amounts 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. At December 31, 2015, Sempra Energy’s and SDG&E’s Consolidated Balance Sheets include assets of $362 million in Other Regulatory Assets (long-term), of which $359 million is related to CPUC-regulated operations and $3 million is related to FERC-regulated operations, for costs incurred and the estimated resolution of pending claims. In September 2015, SDG&E filed an application with the CPUC requesting rate recovery of these costs, as we discuss in Note 14 of the Notes to Consolidated Financial Statements. SDG&E requested a CPUC decision by the end of 2016 and is proposing to recover the costs in rates over a six- to ten-year period. Intervening parties have recommended a phased approach, with Phase 1 addressing the reasonableness of SDG&E’s actions leading up to the fires and a CPUC decision in the second half of 2017. Phase 2 would address the reasonableness of settlements entered into by SDG&E, with a CPUC decision in the second half of 2018.

Recovery of these costs in rates will require future regulatory approval. SDG&E will continue to assess the likelihood, amount and timing of such recoveries in rates. Should SDG&E conclude that recovery of excess wildfire costs in rates is no longer probable, at that time SDG&E would 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, at December 31, 2015, the resulting after-tax charge against earnings would have been up to approximately $213 million. A failure to obtain substantial or full recovery of these costs from customers, 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. 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

We discuss regulatory and other matters related to SONGS in the Notes to Consolidated Financial Statements as follows:

In Note 13:

§	SONGS Steam Generator Replacement Project

§	Settlement Agreement to Resolve the CPUC’s Order Instituting Investigation (OII) into the SONGS Outage (SONGS OII)

§	Settlement with Nuclear Electric Insurance Limited (NEIL)

§	Nuclear Regulatory Commission Proceedings

§	Nuclear Decommissioning and Funding

§	Nuclear Decommissioning Trusts

§	Asset Retirement Obligation and Spent Nuclear Fuel

In Note 15:

§	Legal Proceedings – SDG&E – Lawsuit Against Mitsubishi Heavy Industries, Ltd.

§	Environmental Issues

§	Nuclear Insurance

§	U.S. Department of Energy (DOE) Nuclear Fuel Disposal

We also discuss SONGS in “Risk Factors” in our 2015 Annual Report on Form 10-K.

Investment in Wind Farm

In 2011, the CPUC and FERC approved SDG&E’s estimated $285 million tax equity investment in the Rim Rock wind farm project. SDG&E and the project developer were in dispute regarding whether all conditions precedent in the contribution agreement had been achieved by the developer of the project. As a result, SDG&E had not made the investment. On February 11, 2016, SDG&E, the project developer and several of the project developer’s parent and affiliated entities entered into a conditional settlement agreement. Under the conditional settlement agreement, among other things, the parties agreed to terminate the tax equity investment arrangement, continue the power purchase agreement for the wind farm generation, and release all claims against each other. The conditional settlement agreement is not fully effective until approved by the CPUC. We discuss this matter further in Note 15 of the Notes to Consolidated Financial Statements.

Electric Rate Reform – State of California Assembly Bill 327

In October 2013, the Governor of California signed Assembly Bill (AB) 327. This bill became law on January 1, 2014. This law restores the authority to establish electric residential rates for electric utility companies in California to the CPUC and removes the rate caps established in AB 1X adopted in early 2001 during California’s energy crisis, as well as SB 695 adopted in 2009. Additionally, the bill provides the CPUC the authority to adopt up to a $10.00 monthly fixed charge for all non-CARE (California Alternate Rates for Energy) residential customers and up to a $5.00 monthly fixed charge for CARE customers. Beginning January 1, 2016, the maximum allowable fixed charge may be adjusted by no more than the annual percentage increase in the Consumer Price Index for the prior calendar year. In February 2014, SDG&E filed comprehensive proposals with the CPUC that provide a roadmap to reforming electric residential rate design beginning in 2015 and continuing through 2018, consistent with the provisions of AB 327. In July 2015, the CPUC adopted a revised Administrative Law Judge (ALJ)-proposed decision that establishes comprehensive reform and a framework for rates that are more transparent, fair and sustainable. The revised ALJ-proposed decision directs changes beginning in summer 2015 and provides a path for continued reforms through 2020, including a minimum monthly bill of $10 ($5 for CARE customers). The changes also include fewer rate tiers and a gradual reduction in the difference between the tiered rates, similar to the tier differential that existed prior to the 2000-2001 Energy Crisis. The number of tiers was reduced from four to three in 2015 and will be reduced to two in 2016. The rate differential between the highest and lowest tiers was reduced from approximately 2.4 times to 2.18 times in 2015, and will reduce to 1.25 times by 2019. The revised ALJ-proposed decision also directs the utilities to pursue expanded time of use rates and implements a super user electric (SUE) surcharge in 2017 for usage that exceeds average customer usage by approximately 400 percent. The adopted decision still allows the utilities to seek a fixed charge, but sets certain conditions for its implementation, which would be no sooner than 2020. The changes implemented should result in significant rate relief for higher-use SDG&E customers who do not exceed the SUE threshold and will result in a rate structure that better aligns rates with the actual cost to serve customers.

In July 2014, the CPUC initiated a rulemaking proceeding to develop a successor tariff to the state’s existing net energy metering (NEM) program pursuant to the provisions of AB 327, which required the CPUC to establish a revised NEM tariff or similar program by December 31, 2015. The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable generation. It was originally established in California in 1995 with the adoption of SB 656, as codified in Section 2827 of the Public Utilities Code. Currently, customers who install and operate eligible renewable generation facilities of one megawatt or less may choose to participate in the NEM program. Under NEM, customer-generators receive a full retail-rate for the energy they generate that is fed back to the utility’s power grid. This occurs during times when the customer’s generation exceeds their own energy usage. In addition, if a NEM customer generates any electricity over the annual measurement period that exceeds their annual consumption, they receive compensation at a rate equal to a wholesale energy price.

California Senate Bill 350

SB 350, signed into law in October 2015, creates new requirements for the utilities in the areas of renewable procurements, energy efficiency, resource planning, and electric vehicle (EV) infrastructure. Specifically, the state mandated renewable portfolio standard will be raised to 50 percent by 2030 and requires all load serving entities, including SDG&E, to file integrated resource plans that will ultimately enable the electric sector to achieve reductions in greenhouse gas (GHG) emissions of 40 percent compared to 1990 levels by 2030. SB 350 also clearly specifies that the utilities will be asked to file applications with the CPUC that highlight how they can help with the development and expansion of the electric charging infrastructure necessary to support the growth of the EV market expected due to the state’s alternative fuel vehicle policy initiative. SB 350 also enhances focus on improving efficiency in older buildings. We expect to meet the higher renewable portfolio standard and GHG emissions reductions requirement and are supportive of greater infrastructure development to support electric vehicle charging. Our Electric Vehicle Charging Program, which we discuss in Note 14 of the Notes to Consolidated Financial Statements, does not include potential additional opportunities associated with SB 350.

SoCalGas Matters

Aliso Canyon Natural Gas Storage Facility Gas Leak

In October 2015, SoCalGas discovered a leak at one of its injection and withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility, located in Los Angeles County, which has been operated by SoCalGas since 1972. SoCalGas worked closely with several of the world's leading experts to stop the leak, including planning and obtaining all necessary approvals for drilling relief wells. After discovering the leak, SoCalGas made seven unsuccessful attempts to plug SS25 by pumping fluids down the well shaft. In early December 2015, SoCalGas began drilling a relief well designed to stop the leak by plugging the well at its base. On February 11, 2016, SoCalGas began pumping heavy fluids through the relief well into SS25 near the base of the well, which controlled the flow of natural gas through the well and stopped the leak. In order to permanently seal the well and consistent with directives from the DOGGR and CPUC, SoCalGas then injected cement into SS25 at its base, and on February 18, 2016, the DOGGR confirmed that the well was permanently sealed.

Various governmental agencies including the DOGGR, Los Angeles County Department of Public Health, SCAQMD, CARB, CPUC, U.S. Environmental Protection Agency, Los Angeles District Attorney’s Office, and California Attorney General’s Office, are investigating this incident. SoCalGas has been working in close cooperation with these agencies.

As of February 24, 2016, 83 lawsuits have been filed against SoCalGas, some of which have also named Sempra Energy and, in derivative claims on behalf of Sempra Energy and SoCalGas, certain officers and directors of Sempra Energy and SoCalGas. These various lawsuits assert causes of action for negligence, strict liability, property damage, fraud, nuisance, trespass, and breach of fiduciary duties, among other things, and additional litigation may be filed against us in the future related to this incident. Many of these complaints seek class action status, compensatory and punitive damages, injunctive relief and attorneys’ fees. The Los Angeles City Attorney and Los Angeles County Counsel have also filed a complaint on behalf of the people of the State of California against SoCalGas for public nuisance and violation of the California Unfair Competition Law. The California Attorney General, acting in her independent capacity and on behalf of the people of the State of California and the CARB, joined this lawsuit. The complaint, as amended to include the California Attorney General, adds allegations of violations of certain California Health and Safety Code and California Government Code sections. It seeks an order for injunctive relief, to abate the public nuisance, and to impose civil penalties. The SCAQMD also filed a complaint against SoCalGas seeking civil penalties for alleged violations of several nuisance-related statutory provisions arising from the leak and delays in stopping the leak. That suit seeks up to $250,000 in civil penalties for each day the violations occurred. On February 2, 2016, the Los Angeles District Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties for alleged failure to provide timely notice of the leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a), and for violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public.

On January 6, 2016, the Governor of the State of California issued the Governor’s Order proclaiming a state of emergency to exist in Los Angeles County due to the natural gas leak at the Aliso Canyon facility. The Governor’s Order implements various orders with respect to:

§	stopping the leak;

§	protecting public health and safety;

§	ensuring accountability; and

§	strengthening oversight.

We provide further detail regarding the Governor’s Order in Note 15 of the Notes to Consolidated Financial Statements.

Additional hearings in the state legislature as well as with various other regulatory agencies have been or are expected to be scheduled, additional legislation has been proposed in the state legislature, and additional laws, orders, rules and regulations may be adopted.

The costs to comply with the various laws, orders, rules and regulations arising out of this incident could be significant and to the extent not covered by insurance or in customer rates, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Natural gas withdrawn from storage is important for ensuring service reliability during peak demand periods, including heating needs in the winter, as well as peak electric generation needs in the summer. Aliso Canyon, with a storage capacity of 86 Bcf, is the largest storage facility and an important element of SoCalGas’ delivery system, serving millions of homes and businesses across Southern California. Aliso Canyon represents 63 percent of SoCalGas’ owned natural gas storage capacity. SoCalGas has not injected natural gas into Aliso Canyon since October 25, 2015, and in accordance with the Governor’s Order and subject to contrary CPUC reliability-based direction, SoCalGas will continue this moratorium on further injections until the completion of a review, utilizing independent experts, of the safety of each of the storage wells and air quality in the surrounding communities, and an evaluation by an independent panel of scientific and medical experts on whether additional measures are needed to protect public health. We are also currently reviewing the recently released DOGGR safety review requirements associated with returning Aliso Canyon to an active injection/withdrawal status. If this facility were to be taken out of service for any meaningful period of time, it could result in an impairment of the Aliso Canyon facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At December 31, 2015, the Aliso Canyon facility has a net book value of $243 million, excluding $162 million of construction work in progress for the project to construct a new compression station. Any significant impairment of this asset could have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations for the period in which it is recorded. Higher operating costs and additional capital expenditures incurred by SoCalGas may not be recoverable in customer rates, and our results of operations, cash flows and financial condition may be materially adversely affected.

We discuss this matter further in Note 15 of the Notes to Consolidated Financial Statements and Risk Factors in the 2015 Annual Report on Form 10-K.

Distributed Energy Resources Services (DERS) Tariff

In October 2015, the CPUC approved SoCalGas’ application to offer the DERS Tariff to facilitate the adoption and use of combined heat and power (CHP) energy systems for its customers. The DERS Tariff service allows SoCalGas to install and own CHP energy systems up to 20 MW at customer facilities, and SoCalGas may also operate the systems. DERS systems must meet the efficiency, greenhouse gas and emission standards of the CPUC Self Generation Incentive Program. The DERS Tariff is authorized for ten years from the issuance date of the decision, and all risks and costs associated with the DERS Tariff shall be borne by shareholders and DERS customers.

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

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

Overview

Sempra South American Utilities has historically provided relatively stable earnings and liquidity, and its performance will depend primarily on the ratemaking and regulatory process, environmental regulations, foreign currency rate fluctuations and economic conditions. Sempra South American Utilities is also expected to provide earnings from construction projects when completed and from other investments, but will require substantial funding for these investments.

Revenues at Chilquinta Energía are based on rates set by the National Energy Commission (Comisión Nacional de Energía). The next rate reviews for sub-transmission are expected to be completed in the first half of 2016, with tariff adjustments going into effect retroactively from January 2016. The next rate reviews for distribution are scheduled to be completed, with tariff adjustments also going into effect, in November 2016. Sub-transmission will cover the period from January 2016 to December 2019 and distribution will cover the period from November 2016 to October 2020.

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). The next rate reviews are scheduled to be completed in 2017 and will cover the period from November 2017 to October 2021. We discuss revenues at Sempra South American Utilities in Note 1 of the Notes to Consolidated Financial Statements.

We discuss the impact of tax reform in Chile and Peru in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” above.

Sempra Energy has a combined $722 million in goodwill recorded at December 31, 2015 related to Chilquinta Energía and Luz del Sur. Goodwill is subject to impairment testing annually, as we discuss in Note 1 of the Notes to Consolidated Financial Statements.

Transmission Projects

Chilquinta Energía. Chilquinta Energía has 50-percent ownership in two joint ventures, Eletrans S.A. and Eletrans II S.A., with Sociedad Austral de Electricidad Sociedad Anónima (SAESA) to construct transmission lines in Chile.

In May 2012, Eletrans S.A. was awarded two 220-kilovolt (kV) transmission lines in Chile. The approximately 100-mile, $80 million transmission line extending from Cardones to Diego de Almagro was completed in November 2015. The remaining 50-mile, $85 million transmission line extending from Ciruelos to Pichirropulli is expected to be completed in 2017.

In June 2013, Eletrans II S.A. was awarded two 220-kV transmission lines in Chile. The transmission lines will extend approximately 60 miles, and we estimate the projects will cost approximately $80 million in total and be completed in 2018.

Once the transmission lines are in operation, they will earn a return in U.S. dollars, indexed to the Consumer Price Index, for twenty years and a regulated return thereafter.

Sempra South American Utilities has a U.S. dollar-denominated loan to Eletrans S.A., its affiliate, totaling $72 million outstanding at December 31, 2015 to provide project financing for the construction of transmission lines.

The projects will be financed by the joint venture partners during construction. Other financing may be pursued upon completion of the projects.

Luz del Sur. Luz del Sur has received regulatory approval for an amended transmission investment plan that includes the development and operation of four substations and their related transmission lines in Lima. We estimate that the project will cost approximately $150 million and be in service in 2016 and 2017 as portions are completed. Once in operation, the capitalized cost will earn the regulated return for 30 years. The project will be financed through Luz del Sur’s existing debt program in Peru’s capital markets.

Sempra Mexico

Overview

Sempra Mexico is expected to provide earnings from construction projects when completed and from joint venture investments. We expect projects, joint venture investments and dividends in Mexico to be funded through a combination of available funds, including credit facilities, funds internally generated by the Mexico businesses, securities issuances, project financing, interim funding from the parent, and partnering in joint ventures.

IEnova and PEMEX are 50-50 partners in the joint venture Gasoductos de Chihuahua (GdC). IEnova currently accounts for its 50-percent interest in GdC as an equity method investment. In July 2015, IEnova entered into an agreement to purchase PEMEX’s 50-percent interest in GdC, which at closing would increase its interest from 50 percent to 100 percent. As we discuss in Note 3 of the Notes to Consolidated Financial Statements, the parties are in the process of restructuring the transaction in response to issues raised in the review of the transaction by Mexico’s antitrust commission. The terms and conditions of the revised transaction are still under negotiation, and there can be no assurance that a new agreement will be reached. Any restructured transaction remains subject to satisfactory completion of the Mexican antitrust review and may require further approvals from other Mexican authorities.

In February 2016, management approved a plan to market and sell Sempra Mexico’s Termoeléctrica de Mexicali, a 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As a result, in February 2016, we stopped depreciating the plant and classified the plant as an asset held for sale. The carrying value at December 31, 2015 was $262 million. Although we believe fair value approximates or exceeds the carrying value of the asset, in the event that the estimated sales price from the planned sale of Termoeléctrica de Mexicali is less than the carrying value, we may recognize an impairment loss in our results of operations.

We discuss the impact of Mexican tax reform in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” above.

Pipeline Projects

In October 2012, IEnova was awarded two contracts by the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE) to build and operate an approximately 500-mile pipeline network (Sonora pipeline) 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 was completed in stages, with a section completed in the fourth quarter of 2014 and the final section completed in August 2015. We expect to complete the second segment in 2016. The capacity is fully contracted by the CFE under two 25-year contracts denominated in U.S. dollars.

In 2014, the GdC joint venture and affiliates of PEMEX executed agreements for the development of Los Ramones Norte, a natural gas pipeline of approximately 275 miles and two compression stations, which will connect with the first phase of Los Ramones and run to the vicinity of San Luis Potosi, with an estimated cost of approximately $1.3 billion to $1.5 billion. The GdC joint venture has a 50-percent interest in the project. We expect expenditures for the project to be funded by the joint venture’s cash flows from operations and project financing, plus additional contributions from its partners. We expect to complete the construction and testing of the two compression stations and to begin operation of the pipeline in the first quarter of 2016. The pipeline’s capacity is fully contracted under a 25-year transportation services agreement with PEMEX denominated in Mexican pesos, with a contract rate based on the U.S. dollar investment, adjusted annually for inflation and fluctuation of the exchange rate.

Sempra Mexico has loans to an affiliate of its joint venture with PEMEX totaling $87 million outstanding at December 31, 2015 to finance a portion of its investment in the Los Ramones Norte pipeline project.

In December 2014, Sempra Mexico entered into a natural gas transportation services agreement with CFE for a 25-year term, denominated in U.S. dollars, for 100 percent of the transport capacity of the Ojinaga pipeline, equal to 1.4 Bcf per day. Sempra Mexico will be responsible for the development, construction and operation of the approximately 137-mile, 42-inch pipeline, with an estimated cost of $300 million. We expect the pipeline to begin operations in the first half of 2017.

In July 2015, Sempra Mexico entered into a natural gas transportation services agreement with CFE for a 25-year term, denominated in U.S. dollars, for 100 percent of the transport capacity of the San Isidro pipeline, equal to 1.1 Bcf per day. Sempra Mexico will be responsible for the development, construction and operation of the approximately 14-mile pipeline, with an estimated cost of $110 million. We expect the pipeline to begin operations in the first half of 2017. IEnova continues to monitor CFE project opportunities and carefully analyze CFE bids in order to participate in those that fit its overall growth strategy. Competition for recent pipeline projects has been intense with numerous bidders competing aggressively for these projects. There can be no assurance that IEnova will be successful in bidding for new CFE projects.

The ability to successfully complete pipeline projects, like other major construction projects, is subject to a number of risks and uncertainties. For a discussion of these risks and uncertainties, see “Risk Factors” in our 2015 Annual Report on Form 10-K.

Energía Sierra Juárez

In 2014, we consummated the sale of a 50-percent equity interest in the first phase of Energía Sierra Juárez to a wholly owned subsidiary of InterGen N.V. The project is designed to provide up to 1,200 MW of capacity if fully developed. The 155-MW first phase of the Energía Sierra Juárez wind generation project is fully contracted by SDG&E and began commercial operations in June 2015. Future expansion of Energía Sierra Juárez will depend, among other factors, on the ability to obtain additional power purchase contracts.

Sempra Mexico has a U.S. dollar-denominated loan to Energía Sierra Juárez, its affiliate, totaling $24 million outstanding at December 31, 2015 to finance the first phase of the project.

Energía Costa Azul LNG Terminal

In February 2015, Sempra Natural Gas, IEnova, and a subsidiary of PEMEX entered into a Memorandum of Understanding (MOU) to collaborate in the development of a natural gas liquefaction project at IEnova’s existing regasification terminal at Energía Costa Azul. The MOU defines the basis for the parties to explore PEMEX’s participation in this potential liquefaction project, including joining efforts on its development and structuring agreements that would allow opportunities for PEMEX to become a customer, natural gas supplier and investor; we have also started to share development costs with PEMEX. Energía Costa Azul has profitable long-term regasification contracts for 100 percent of the facility, making the decision to pursue a new liquefaction facility dependent in part on whether the investment in a new liquefaction facility would, over the long term, be more beneficial than continuing to supply regasification services under our existing contracts. In addition, this project requires the receipt of a number of permits and regulatory approvals, finding suitable partners and customers, obtaining financing, negotiating and completing suitable commercial agreements, including joint venture agreements, tolling capacity agreements and construction contracts, and reaching a final investment decision. For a discussion of these risks, see “Risk Factors” in our 2015 Annual Report on Form 10-K.

SEMPRA U.S. GAS & POWER

Sempra Renewables

Overview

Sempra Renewables is developing and investing in renewable energy generation projects that have long-term contracts with electric load serving entities, which provide electric service to end-users and wholesale customers. The renewable energy projects have planned in-service dates through 2016. These projects require construction financing which may come from a variety of sources including operating cash flow, project financing, 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’ 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 the Renewables Portfolio Standard (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.

Black Oak Getty Wind Project

In March 2015, Sempra Renewables acquired the Black Oak Getty Wind project, a 78-MW wind farm under development in Stearns County, Minnesota. Sempra Renewables will complete the development of the wind farm, and we expect the project to be fully operational by the end of 2016. Minnesota Municipal Power Agency has contracted for the energy generated from the project for 20 years upon project completion.

Copper Mountain Solar

Copper Mountain Solar is a photovoltaic generation facility operated and under development by Sempra Renewables in Boulder City, Nevada. When fully developed, the project will be capable of producing up to approximately 550 MW of solar power; it is being developed in multiple phases as power sales become contracted. Copper Mountain Solar is comprised of four separate projects.

Copper Mountain Solar 1 is a 58-MW photovoltaic generation facility currently in operation, which is fully contracted for 20 years to PG&E.

Copper Mountain Solar 2 is divided into two phases, placed in service in 2012 and 2015, totaling 150 MW, and is fully contracted to PG&E for 25 years. In July 2013, we completed the sale of 50 percent of our equity in Copper Mountain Solar 2 to Con Edison Development, as we discuss in Note 3 of the Notes to Consolidated Financial Statements.

Copper Mountain Solar 3 achieved full commercial operation in April 2015, and totals 250 MW. The cities of Los Angeles and Burbank have contracted for all of the solar power at Copper Mountain Solar 3 for 20 years. In addition to solar power, the power sales agreement provides the cities of Los Angeles and Burbank the option to purchase the Copper Mountain Solar 3 facility at years 10, 15 and 20 of the contract term, or upon earlier termination of the agreement. In March 2014, we completed the sale of 50 percent of our equity in Copper Mountain Solar 3 to Con Edison Development, as we discuss in Note 3 of the Notes to Consolidated Financial Statements.

In July 2014, Sempra Renewables signed a 20-year power sale agreement with Southern California Edison Company (Edison) for all of the solar power from Copper Mountain Solar 4 beginning in 2020. The CPUC approved the power sale agreement in March 2015. We expect Copper Mountain Solar 4 to be in service in 2016. Sempra U.S. Gas & Power will market the output from Copper Mountain Solar 4 before the start of the Edison contract term. Copper Mountain Solar 4 will total 94 MW when completed.

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, with 150 MW currently in operation in a joint venture with Con Edison Development. In June 2015, Sempra Renewables signed a 20-year power sale agreement with Edison for 100 MW of solar power from the second phase of Mesquite Solar. The CPUC approved the power sale agreement in December 2015. In July 2015, Sempra Renewables signed a 25-year power sale agreement with the Western Area Power Administration on behalf of the U.S. Department of the Navy for 150 MW of solar power from the third phase of Mesquite Solar. We expect the second and third phases of Mesquite Solar to be in service by the end of 2016.

Sempra Natural Gas

Rockies Express

Sempra Natural Gas owns a 25-percent interest in Rockies Express, a partnership that operates the REX natural gas pipeline, which links the Rocky Mountains region to the upper Midwest and the eastern United States. All of REX’s original capacity sales provide for west-to-east service. Sempra Natural Gas has an agreement for such capacity on REX through November 2019. The capacity costs are offset by revenues from releases of the capacity contracted to third parties. Certain capacity release commitments totaling $22 million concluded during 2013. Contracting activity related to that capacity has not been sufficient to offset all of our capacity payments to Rockies Express.

In November 2013, FERC issued a decision ruling that east-to-west service offerings within a single REX rate zone would not result in potential rate reductions under provisions in the original customers’ west-to-east contracts (“most favored nation” provisions). In December 2013, certain west-to-east customers sought rehearing of that decision. In 2014 and 2015, Rockies Express reached settlements with these west-to-east customers, and the customers’ requests for rehearing have been withdrawn.

In March 2015, Rockies Express requested FERC approval of the 0.8 Bcf per day Zone 3 Capacity Enhancement Project. The project is an expansion of REX’s east-to-west capability, currently 1.8 Bcf per day. Rockies Express has secured binding financial commitments with seven shippers totaling 0.76 Bcf per day of capacity for east-to-west transportation services for a term of 15 years originating at or near Clarington, Ohio. We expect the project to be in-service in the fourth quarter of 2016. This expansion, with an estimated cost of approximately $530 million, will require additional capital investment by the partners and is subject to regulatory approval. When completed, REX’s total east-to-west capability within Zone 3 will be 2.6 Bcf per day.

In April 2015, Sempra Natural Gas invested $113 million in Rockies Express to repay project debt that matured in early 2015.

Natural Gas Storage

Our natural gas storage assets include operational and development assets at Bay Gas in Alabama and Mississippi Hub in Mississippi, as well as our development project, LA Storage, LLC (LA Storage) in Louisiana. LA Storage could be positioned to support LNG export from the Cameron LNG JV terminal and other liquefaction projects, if anticipated cash flows support further investment. However, changes in the U.S. natural gas market could also lead to diminished natural gas storage values.

Historically, the value of natural gas storage services has positively correlated with the difference between the seasonal prices of natural gas, among other factors. In general, over the past several years, seasonal differences in natural gas prices have declined, which have contributed to lower prices for storage services. As our legacy (higher rate) sales contracts mature at our Bay Gas and Mississippi Hub facilities, replacement sales contract rates have been and could continue to be lower than has historically been the case. Lower sales revenues may not be offset by cost reductions, which could lead to depressed asset values. In addition, our LA Storage development project may be unable to attract cash flow commitments sufficient to support further investment or to extend its FERC construction permit beyond the current expiration date of June 2017. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage pipeline, that is not contracted.

We perform recovery testing of our recorded asset values when market conditions indicate that such values may not be recoverable. In the event such values are not recoverable, we would consider the fair value of these assets relative to their recorded value. To the extent the recorded (carrying) value is in excess of the fair value, we would record a noncash impairment charge. The recorded value of our long-lived natural gas storage assets at December 31, 2015 is $1.5 billion. A significant impairment charge related to our gas storage assets would have a material adverse effect on our results of operations in the period in which it is recorded.

Sempra Natural Gas has 42 Bcf of operational working natural gas storage capacity (20 Bcf at Bay Gas and 22 Bcf at Mississippi Hub). Sempra Natural Gas may, over the long term, develop additional storage capacity at its facilities.

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, a salt cavern development project in Cameron Parish, Louisiana. Sempra Natural Gas owns 77 percent of the project and ProLiance Transportation LLC owns the remaining 23 percent. The project’s location provides access to several LNG facilities in the area.

Cameron Liquefaction

Cameron LNG JV Liquefaction Project. We discuss the 2014 formation of the Cameron LNG JV, including the contribution of our share of equity to the joint venture through the contribution of the Cameron LNG, LLC regasification terminal in Hackberry, Louisiana, in Note 3 of the Notes to Consolidated Financial Statements. The existing regasification terminal is capable of processing 1.5 Bcf of natural gas per day and it currently 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 (MMcf) of natural gas per day through 2029. The agreement allows the customer to pay capacity reservation and usage fees to use the facilities to receive, store and regasify the customer’s LNG. Sempra Natural Gas also may enter into short-term supply agreements to purchase LNG to be received, stored, and regasified at the terminal for sale to other parties.

The current liquefaction project under construction, which will utilize Cameron LNG JV’s existing facilities, is comprised of three liquefaction trains designed to a nameplate capacity of 13.9 million tonnes per annum (Mtpa) of LNG with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. We expect the project to achieve commercial operation of all three trains in 2018, and have the first year of full operations in 2019. The anticipated incremental investment in the three-train liquefaction project is estimated to be approximately $7 billion, including the cost of the lump-sum, turnkey construction contract, development engineering costs and permitting costs, but excluding capitalized interest and other financing costs. The majority of the incremental investment will be project-financed and the balance provided by the project partners. We expect that our remaining equity requirements to complete the project will be met by a combination of our share of cash generated from each liquefaction train as it comes on line and additional cash contributions. If construction, financing or other project costs are higher than we currently expect, we may have to contribute additional cash exceeding our current expectations. 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 $10 billion.

The joint venture has authorization to export LNG to both Free Trade Agreement (FTA) countries and to countries that do not have an FTA with the United States. Cameron LNG JV has 20-year liquefaction and regasification tolling capacity agreements in place with ENGIE S.A. (formerly GDF SUEZ S.A.) and affiliates of Mitsubishi Corporation and Mitsui & Co, Ltd., that subscribe the full nameplate capacity of the facility.

Sempra Natural Gas has agreements totaling 1.45 Bcf per day of firm natural gas transportation service to the Cameron LNG JV facilities on the Cameron Interstate Pipeline with ENGIE S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd. The terms of these agreements are concurrent with the liquefaction and regasification tolling capacity agreements.

Construction on the current project began in the second half of 2014 under an engineering, procurement and construction (EPC) contract with a joint venture between CB&I Shaw Constructors, Inc., a wholly owned subsidiary of Chicago Bridge & Iron Company N.V., and Chiyoda International Corporation, a wholly owned subsidiary of Chiyoda Corporation.

In August 2014, Sempra Energy and the project partners executed project financing documents for senior secured debt in an initial aggregate principal amount up to $7.4 billion for the purpose of financing the cost of development and construction of the Cameron LNG JV liquefaction project. Concurrently, Sempra Energy entered into completion guarantees under which it has severally guaranteed 50.2 percent of the debt, or a maximum principal amount of $3.7 billion. The project financing and completion guarantees became effective on October 1, 2014, and will terminate upon financial completion of the project, which will occur upon satisfaction of certain conditions, including all three trains achieving commercial operation and meeting certain operational performance tests. We expect the project to achieve financial completion and the completion guarantees to be terminated in the second half of 2019.

Large-scale construction projects like the design, development and construction of the Cameron LNG JV liquefaction facility involve numerous risks and uncertainties, including among others, the potential for unforeseen engineering problems, substantial construction delays and increased costs. As noted above, Cameron LNG JV has a turnkey EPC contract with a joint venture between CB&I Shaw Constructors, Inc. and Chiyoda International Corporation. If the contractor becomes unwilling or unable to perform according to the terms and timetable of the EPC contract, Cameron LNG JV would be required to engage a substitute contractor, which would result in project delays and increased costs, which could be significant. For a discussion of these risks and other risks relating to the development of the Cameron LNG JV liquefaction project that could adversely affect our future performance, see “Risk Factors” in our 2015 Annual Report on Form 10-K.

Cameron LNG JV has a terminal services agreement with one customer that requires the customer to pay capacity reservation and usage fees to use its facilities to receive, store and regasify the customer’s LNG. There is a termination agreement in place that will result in the termination of this services agreement at the point during construction of the new liquefaction facilities where piping tie-ins to the existing regasification terminal become necessary. Based on the full notice to proceed that was issued to Cameron LNG JV’s EPC contractor in October 2014, we expect this termination date to occur during the first half of 2017.

In December 2014, Cameron LNG JV filed with the DOE for authorization to match the total export volumes allowed to be exported to FTA countries under the FERC permit. This would allow for increased export from the three-train facility of up to 2.95 Mtpa. In April 2015, Cameron LNG JV filed the corresponding DOE Non-FTA permit application.

Proposed Additional Cameron Liquefaction Expansion. Cameron LNG JV is also pursuing the permitting to expand the current configuration from the current three liquefaction trains. The expansion project is expected to include up to two additional liquefaction trains, capable of increasing LNG production capacity by approximately 9 Mtpa to 10 Mtpa, and one additional full containment LNG storage tank; a fourth tank was permitted with the base liquefaction project but not built. In February 2015, Cameron LNG JV filed the DOE FTA application and the pre-filing application at FERC for the two additional trains and one containment tank. In May 2015, the joint venture filed a corresponding DOE Non-FTA permit application. In July 2015, Cameron LNG JV received approval of the DOE FTA application. In September 2015, Cameron LNG JV submitted the FERC application and was formally noticed by FERC in October 2015. On February 12, 2016, Cameron LNG JV received the FERC environmental assessment, and expects to receive the FERC permit in the second quarter of 2016. Under the Cameron LNG JV financing agreements, expansion of the Cameron LNG JV facilities beyond the first three trains is subject to certain restrictions and conditions, including among others, timing restrictions on expansion of the project unless appropriate prior consent is obtained from lenders. In addition, expansion of the Cameron LNG JV facilities beyond the first three trains is subject to a number of risks and uncertainties, including completing the required commercial agreements, securing all necessary permits and approvals, obtaining financing, reaching a final investment decision and other factors associated with the potential investment. See “Risk Factors” in our 2015 Annual Report on Form 10-K.

We discuss the deconsolidation of Cameron LNG, LLC, the Cameron LNG JV project financing obligations and Sempra Energy’s completion guarantee further in Notes 3 and 4 of the Notes to Consolidated Financial Statements.

Other LNG Liquefaction Development

Design, regulatory and commercial activities are ongoing for potential LNG liquefaction developments at Sempra Mexico’s Energía Costa Azul facility and at our Port Arthur, Texas site. For these development projects, we have met with potential customers and determined an interest in long-term contracts for LNG supplies beginning in the 2020 to 2023 time frame.

Port Arthur. In March 2015, Sempra Natural Gas submitted a request to the FERC to initiate the pre-filing review for the proposed Port Arthur LNG natural gas liquefaction and export facility in Port Arthur, Texas. The proposed project is designed to include two natural gas liquefaction trains with total export capability of approximately 10 Mtpa, or 1.4 Bcf per day; two 160,000-cubic-meter storage tanks; marine facilities for vessel berthing and loading; natural gas liquids and refrigerant storage; feed gas pre-treatment; truck loading and unloading areas; and combustion turbine generators for self-generation of electrical power.

In March 2015, Sempra Natural Gas also submitted a request to the FERC to initiate the pre-filing review for the proposed Port Arthur pipeline project. The proposed project consists of two 42-inch-diameter feed gas pipelines (7 and 27 miles long), two compressor stations, receipt meter stations, and other appurtenant facilities in Orange and Jefferson Counties, Texas, and Cameron Parish, Louisiana. The pipelines would provide up to 1.6 Bcf per day of capacity to the Port Arthur LNG facilities.

In March and June 2015, Sempra Natural Gas filed permit applications with the DOE for authorization to export the LNG produced from the proposed project to all current and future FTA and Non-FTA countries, respectively. In August 2015, Sempra Natural Gas received authorization from the DOE to export the LNG produced from the proposed project to all current and future FTA countries.

In June 2015, Sempra Natural Gas entered into a non-binding MOU with an affiliate of Woodside Petroleum Ltd. (Woodside) to commence discussions and assessments for the potential development of the proposed Port Arthur LNG liquefaction project. In February 2016, Sempra Natural Gas and Woodside entered into a project development agreement for the joint development of the proposed Port Arthur LNG liquefaction project. The agreement specifies how the parties will share costs, and establishes a framework for the parties to work jointly on permitting, design, engineering, commercial and marketing activities associated with developing the Port Arthur LNG liquefaction project.

Development of the Port Arthur LNG liquefaction project is subject to a number of risks and uncertainties, including completing the required commercial agreements, such as joint venture agreements, tolling capacity agreements or gas supply and LNG sales agreements; completing construction contracts; securing all necessary permits and approvals; obtaining financing and incentives; reaching a final investment decision; and other factors associated with the potential investment. See “Risk Factors” in our 2015 Annual Report on Form 10-K.

Energía Costa Azul. We further discuss Sempra Natural Gas’ participation in potential LNG liquefaction development at Sempra Mexico’s Energía Costa Azul facility above under “Sempra Mexico − Energía Costa Azul LNG Terminal.”

LNG Liquefaction Development Costs

Total expenditures on LNG liquefaction development for the year ended December 31, 2015 were $34 million, including capitalized costs of $17 million (pretax). After-tax LNG development costs expensed for the year ended December 31, 2015 were $10 million. We expect to expense approximately $20 million to $25 million, after-tax, in 2016 for liquefaction and LNG integrated midstream development costs.

RBS Sempra Commodities

In three separate transactions in 2010 and one in early 2011, we and The Royal Bank of Scotland plc (RBS), our partner in the RBS Sempra Commodities joint venture, sold substantially all of the businesses and assets of our commodities-marketing partnership. The investment balance of $67 million at December 31, 2015 reflects remaining distributions expected to be received from the partnership as it is dissolved. The amount of distributions, if any, may be impacted by the matters we discuss related to RBS Sempra Commodities under “Other Litigation” in Note 15 of the Notes to Consolidated Financial Statements. 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.

OTHER SEMPRA ENERGY MATTERS

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, when in decline, negatively affect profitability at Sempra Natural Gas. Also, a reduction in projected global demand for LNG could result in increased competition among those working on projects in an environment of declining LNG demand, such as the Sempra Energy-sponsored export initiatives. For a discussion of these risks and other risks involving changing commodity prices, see “Risk Factors” in our 2015 Annual Report on Form 10-K.

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 and transparency requirements 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 latter of which is pending final approval. 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 and extent of our hedging programs, because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to mitigate and may be restricted on the size of our hedging program.

Our future performance depends substantially on the timing and success of our business development efforts and our construction, maintenance and capital projects. We discuss this and additional matters that could affect our future performance in Notes 14 and 15 of the Notes to Consolidated Financial Statements and in “Risk Factors” in our 2015 Annual Report on Form 10-K.

LITIGATION

We describe legal proceedings that could adversely affect our future performance in Note 15 of the Notes to Consolidated Financial Statements.

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.

We discuss revenue recognition in Note 1 and the additional market-risk information regarding derivative instruments in Note 9 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, 2015 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.

Sempra Mexico, Sempra Renewables and Sempra Natural Gas 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. A hypothetical 10-percent unfavorable change in commodity prices would not have resulted in a material change in the fair value of our commodity-based financial derivatives for these segments as of December 31, 2015 and 2014. 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.

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, 2015, 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.

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 for long-term debt at December 31, 2015 and 2014:

NOMINAL AMOUNT OF LONG-TERM DEBT AT DECEMBER 31(1)
(Dollars in millions)
	2015									2014
	Sempra Energy									Sempra Energy
	Consolidated			SDG&E			SoCalGas			Consolidated			SDG&E			SoCalGas
Utility fixed-rate		$	6,362		$	3,849		$	2,513		$	6,049		$	4,136		$	1,913
Utility variable-rate			455			455			―			325			325			―
Non-utility fixed-rate			6,780			―			―			5,733			―			―
Non-utility variable-rate			166			―			―			240			―			―

(1)

Excluding commercial paper classified as long-term debt at Sempra Energy and SDG&E, capital lease obligations, build-to-suit lease and interest rate swaps, and before reductions/increases for unamortized discount/premium and reductions for debt issuance costs.

In order to provide the most appropriate and meaningful quantitative and qualitative measures concerning the market risk associated with debt, in 2015 we changed our measure of interest rate risk from a 1-year VaR measure to a one-percent interest-rate sensitivity result applied to our effective variable-rate debt position. We consider the cash flow and earnings impact of a change in interest rates more meaningful to our stakeholders than the prior use of VaR applied to our total debt portfolio.

Interest rate risk sensitivity analysis measures interest rate risk by calculating the estimated changes in earnings that would result from a hypothetical change in market interest rates. If interest rates changed by one percent on all of Sempra Energy’s effective variable-rate, long-term debt at December 31, 2015, the change in earnings over the next 12 months would be $5 million for the period ending December 31, 2016, including $3 million at SDG&E. If interest rates changed by one percent on all of Sempra Energy’s effective variable-rate, long-term debt at December 31, 2014, the change in earnings over the next 12 months would have been $4 million for the period ending December 31, 2015, including $2 million at SDG&E. These hypothetical changes in earnings are based on our long-term debt position after the effect of interest rate swaps.

We provide further information about interest rate swap transactions in Note 9 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 recovered in future rates.

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:

§	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 under 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

Sempra South American Utilities

We have investments in entities whose functional currency is not the U.S. dollar, exposing us to foreign exchange movements, primarily in currencies in Chile and Peru.

Sempra Mexico

We discuss our foreign currency exposure related to income taxes and inflation at our Mexican subsidiaries in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes – Foreign Currency Exchange Rate and Inflation Impact on Income Taxes and Related Economic Hedging Activity.” If IEnova’s potential acquisition of the remaining 50-percent interest in GdC is completed, Sempra Mexico will be subject to additional foreign currency rate risk. However, similar to our current Mexican operations, GdC’s functional currency is the U.S. dollar and its assets are covered by long-term, U.S. dollar-based contracts.

Our primary objective in reducing foreign currency risk is to preserve the economic value of our foreign investments and to reduce earnings volatility that would otherwise occur due to exchange rate fluctuations. We may offset material cross-currency transactions and earnings 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 against the currencies of Mexico, Chile and Peru in which we have operations and investments are as follows:

(Dollars in millions)	Hypothetical effects
Translation of 2015 earnings to U.S. dollars(1)	$	(2	)
Transactional exposure(2)		3
Translation of net assets of foreign subsidiaries and investment in foreign entities(3)		(17	)

(1	)	Amount represents the impact to earnings, primarily at our South American businesses, for a change in the average exchange rate throughout the reporting period.
(2	)	Amount primarily represents the effects of currency exchange rate movement from year-end 2015 on monetary assets and liabilities and translation of non-U.S. deferred income tax balances at our Mexican subsidiaries, which we discuss in "Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes" above.
(3	)	Amount represents the effects of currency exchange rate movement from year-end 2015 recorded to other comprehensive income at the end of each reporting period, primarily at our South American businesses.

Foreign Inflation Risk

Monetary assets and liabilities at our Mexican subsidiaries that are denominated in U.S. dollars may fluctuate significantly throughout the year. Based on a net monetary liability position of $1.4 billion, including those related to our investments in joint ventures, at December 31, 2015, the hypothetical effect on Sempra Energy for every one percent increase in the Mexican inflation rate is approximately $4 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 AND ESTIMATES
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		As regulated entities, the California Utilities’ rates, as set and monitored by regulators, are designed to recover the cost of providing service and provide the opportunity to earn a competitive return on their investments. The California Utilities record regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover that asset from customers in future rates. Similarly, regulatory liabilities are recorded for amounts recovered in rates in advance or in excess of costs incurred. The California Utilities assess probabilities of future rate recovery associated with regulatory account balances at the end of each reporting period and whenever new and/or unusual events occur, such as: § changes in the regulatory and political 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 evaluated and adjusted if appropriate.
Effect if Different Assumptions Used		Adverse legislative or regulatory actions could materially impact the amounts of our regulatory assets and liabilities and could materially adversely impact our financial statements. 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, 13, 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, regulations, interpretations and rulings § 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 6 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 6 of the Notes to Consolidated Financial Statements.
SEMPRA ENERGY, SDG&E AND SOCALGAS (CONTINUED)
DERIVATIVES
Assumptions & Approach Used		We record 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 quoted prices 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 are 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 regulatory accounting principles generally apply to their contracts. We provide details of our derivative financial instruments in Note 9 of the Notes to Consolidated Financial Statements.
DEFINED BENEFIT PLANS
Assumptions & Approach Used		To measure our pension and other postretirement obligations, costs and liabilities, we rely on several assumptions. We consider current market conditions, including interest rates, in making these assumptions. We review these assumptions annually 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 the effects of the assumptions on earnings, may result in a significant impact to the amount of pension and postretirement benefit expense we record. For plans other than those at the California Utilities, the approximate annual effect on earnings of a 100 basis point increase or decrease in the assumed discount rate would be less than $1 million and the effect of a 100 basis point increase or decrease in the assumed rate of return on plan assets would be less than $3 million. We provide additional information, including the impact of increases and decreases in the health care cost trend rate, in Note 7 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 estimated based on a site specific study performed no less than every three years. The estimate 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 initiation and duration of decommissioning activities
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. SDG&E’s nuclear decommissioning expenses are subject to rate recovery and, therefore, rate-making accounting treatment is applied to SDG&E’s nuclear decommissioning activities. SDG&E recognizes a regulatory asset, or liability, to the extent that its SONGS ARO exceeds, or is less than, the amount collected from customers and the amount earned in SDG&E’s Nuclear Decommissioning Trusts. We provide additional detail in Notes 13 and 15 of the Notes to the Consolidated Financial Statements.
SEMPRA ENERGY
IMPAIRMENT TESTING OF LONG-LIVED ASSETS, INCLUDING INTANGIBLE 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. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors, changes in key personnel and the overall financial performance of the reporting unit. If, after assessing these qualitative factors, we determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then we perform the two-step 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 compare that to the carrying value. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as 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 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 has $819 million of goodwill on its Consolidated Balance Sheet at December 31, 2015, of which $722 million is attributable to our operations in South America. Based on our quantitative assessment of the goodwill attributable to our operations in South America, we determined that the estimated fair values of the reporting units to which this goodwill was allocated exceeded their carrying values as of October 1, 2015, our most recent goodwill impairment testing date. We discuss goodwill in Note 1 of the Notes to Consolidated Financial Statements.
SEMPRA ENERGY (CONTINUED)
CARRYING VALUE OF EQUITY METHOD INVESTMENTS
Assumptions & Approach Used		We generally account for investments under the equity method when we have significant influence over, but do not have control of, the investee. 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 and liquefied natural gas § competing fuels (primarily propane) and electricity § estimated future power generation and associated tax credits § renewable power price expectations
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 Notes 4 and 10 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 service 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, electric reliability, 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 obtaining and completing major projects and 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 and Sempra Renewables)

Key noncash performance indicators include plant availability and capacity factors and sales volume at our renewable energy facilities and natural gas-fired generating plant. For competitive reasons, we do not disclose plant availability factors. We discuss the other indicators 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)

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, legal and regulatory conditions, decisions and developments;

§	deviations from regulatory precedent or practice that result in a reallocation of benefits or burdens among shareholders and ratepayers, and delays in regulatory agency authorization to recover costs in rates from customers;

§	the resolution of civil and criminal litigation and regulatory investigations;

§	risks posed by decisions and actions of third parties who control the operations of investments in which we do not have a controlling interest, and risks that our partners or counterparties will be unable or unwilling to fulfill their contractual commitments;

§	capital markets conditions, including the availability of credit and the liquidity of our investments, and inflation, interest and currency exchange rates;

§	the ability to win competitively bid infrastructure projects against a number of strong competitors willing to aggressively bid for these projects;

§	disallowance of regulatory assets associated with, or decommissioning costs of, the San Onofre Nuclear Generating Station facility due to increased regulatory oversight, including motions to modify settlements;

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

§	the impact on reliability of San Diego Gas & Electric Company’s (SDG&E) electric transmission and distribution system due to increased amount and variability of power supply from renewable energy sources and increased reliance on natural gas and natural gas transmission systems;

§	the impact on competitive customer rates of the growth in distributed and local power generation and the corresponding decrease in demand for power delivered through SDG&E’s electric transmission and distribution system;

§	the inability or determination not to enter into long-term supply and sales agreements or long-term firm capacity agreements due to insufficient market interest, unattractive pricing or other factors; 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 2015 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 18, 2016, there were approximately 29,940 record holders of our common stock.

The following table shows Sempra Energy quarterly common stock data:

QUARTERLY COMMON STOCK DATA

	First		Second		Third		Fourth
	quarter		quarter		quarter		quarter
2015
Market price
High	$	116.21	$	111.09	$	106.70	$	105.78
Low	$	104.64	$	98.67	$	89.44	$	90.52

2014
Market price
High	$	97.48	$	105.25	$	107.81	$	116.30
Low	$	86.73	$	95.15	$	96.13	$	98.34

We declared dividends of $0.70 per share and $0.66 per share in each quarter of 2015 and 2014, respectively. On February 19, 2016, our board of directors approved an increase to our quarterly common stock dividend to $0.755 per share ($3.02 annually), an increase of $0.055 per share ($0.22 annually) from $0.70 per share ($2.80 annually) authorized in February 2015.

SOCALGAS AND SDG&E COMMON STOCK

Pacific Enterprises, 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 Statements of Changes in Shareholders’ Equity and Statements 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 – Sempra Energy Consolidated,” “Overview – California Utilities” 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 ended December 31, 2015, 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, 2010, 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, 2015. 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 per share amounts)
	At December 31 or for the years then ended
	2015			2014			2013			2012			2011
Sempra Energy Consolidated:
Revenues
Utilities:
Electric	$	5,158		$	5,209		$	4,911		$	4,568		$	3,833
Natural gas		4,096			4,549			4,398			3,873			4,489
Energy-related businesses		977			1,277			1,248			1,206			1,714
Total revenues	$	10,231		$	11,035		$	10,557		$	9,647		$	10,036

Income from continuing operations	$	1,448		$	1,262		$	1,088		$	920		$	1,381
Earnings from continuing operations
attributable to noncontrolling interests		(98	)		(100	)		(79	)		(55	)		(42	)
Call premium on preferred stock of subsidiary		―			―			(3	)		―			―
Preferred dividends of subsidiaries		(1	)		(1	)		(5	)		(6	)		(8	)
Earnings/Income from continuing operations
attributable to common shares	$	1,349		$	1,161		$	1,001		$	859		$	1,331

Attributable to common shares:
Earnings/Income from continuing operations
Basic	$	5.43		$	4.72		$	4.10		$	3.56		$	5.55
Diluted	$	5.37		$	4.63		$	4.01		$	3.48		$	5.51

Dividends declared per common share	$	2.80		$	2.64		$	2.52		$	2.40		$	1.92
Return on common equity		11.7	%		10.4	%		9.4	%		8.6	%		14.2		%
Effective income tax rate		20	%		20	%		26	%		6	%		23		%
Price range of common shares:
High	$	116.21		$	116.30		$	93.00		$	72.87		$	55.97
Low	$	89.44		$	86.73		$	70.61		$	54.70		$	44.78

Weighted average rate base:
SDG&E	$	7,671		$	7,253		$	7,244		$	6,295		$	5,071
SoCalGas	$	4,269		$	3,879		$	3,499		$	3,178		$	2,948

AT DECEMBER 31
Current assets(1)	$	2,891		$	4,184		$	3,997		$	3,695		$	2,332
Total assets(2)	$	41,150		$	39,651		$	37,165		$	36,412		$	33,184
Current liabilities(1)	$	4,612		$	5,069		$	4,369		$	4,258		$	4,152
Long-term debt (excludes current portion)(2)(3)	$	13,134		$	12,086		$	11,174		$	11,534		$	10,013
Short-term debt(4)	$	1,529		$	2,202		$	1,692		$	1,271		$	785
Contingently redeemable preferred stock
of subsidiary(5)	$	―		$	―		$	―		$	79		$	79
Sempra Energy shareholders’ equity	$	11,809		$	11,326		$	11,008		$	10,282		$	9,775
Common shares outstanding		248.3			246.3			244.5			242.4			239.9
Book value per share	$	47.56		$	45.98		$	45.03		$	42.43		$	40.74

(1)	Reflects the adoption of Accounting Standards Update (ASU) 2015-17 on a prospective basis for the year ended December 31, 2015, which requires the presentation of deferred tax assets and liabilities as noncurrent on the balance sheet.
(2)	As adjusted for the retrospective adoption of ASU 2015-03, as we discuss in Note 2 of the Notes to Consolidated Financial Statements.
(3)	Includes capital lease obligations.
(4)	Includes long-term debt due within one year and current portion of capital lease obligations.
(5)	SDG&E redeemed all series of its outstanding shares of contingently redeemable stock in 2013, as we discuss in Note 11 of the Notes to Consolidated Financial Statements.

We discuss the impact of natural gas prices on revenues in 2015, 2014 and 2013 and the changes in our effective income tax rate in 2015 and 2014 in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Changes in Revenues, Costs and Earnings.”

In October 2014, Cameron LNG JV, a joint venture between Sempra Natural Gas and its partners in the Cameron LNG liquefaction project, became effective. Sempra Natural Gas is accounting for its investment in the joint venture under the equity method. We discuss Cameron LNG JV further in Notes 3 and 4 of the Notes to Consolidated Financial Statements.

In the first quarter of 2013, a Sempra Energy subsidiary, IEnova, completed a private offering in the U.S. and outside of Mexico and a concurrent public offering in Mexico of common stock. We discuss the offerings and IEnova further in Note 1 of the Notes to Consolidated Financial Statements.

In June 2013, we recorded a $200 million pretax loss from plant closure related to SDG&E’s investment in SONGS. We discuss this loss further in Note 13 of the Notes to Consolidated Financial Statements.

In 2012, we recorded $239 million in after-tax impairment charges related to our investment in the Rockies Express joint venture. We discuss Rockies Express further in Note 4 of the Notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance – Sempra U.S. Gas & Power.”

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. In conjunction with the transaction, we recorded a $277 million gain (both pretax and after-tax) related to the remeasurement of equity method investments.

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
	2015		2014		2013		2012		2011
SDG&E:
Statement of Operations Data:
Operating revenues	$	4,219	$	4,329	$	4,066	$	3,694	$	3,373
Operating income		1,058		959		782		809		755
Dividends on preferred stock		―		―		4		5		5
Earnings attributable to common shares		587		507		404		484		431

Balance Sheet Data:
Total assets(1)	$	16,515	$	16,260	$	15,337	$	14,705	$	13,517
Long-term debt (excludes current portion)(1)(2)		4,455		4,283		4,485		4,253		4,020
Short-term debt(3)		218		611		88		16		19
Contingently redeemable preferred stock(4)		―		―		―		79		79
SDG&E shareholder's equity		5,223		4,932		4,628		4,222		3,739
SoCalGas:
Statement of Operations Data:
Operating revenues	$	3,489	$	3,855	$	3,736	$	3,282	$	3,816
Operating income		608		521		539		420		486
Dividends on preferred stock		1		1		1		1		1
Earnings attributable to common shares		419		332		364		289		287

Balance Sheet Data:
Total assets(1)	$	12,104	$	10,446	$	9,138	$	9,062	$	8,468
Long-term debt (excludes current portion)(1)(2)		2,481		1,891		1,150		1,400		1,057
Short-term debt(3)		9		50		294		4		257
SoCalGas shareholders’ equity		3,149		2,781		2,549		2,235		2,193

(1)	As adjusted for the retrospective adoption of ASU 2015-03, as we discuss in Note 2 of the Notes to Consolidated Financial Statements.
(2)	Includes capital lease obligations.
(3)	Includes long-term debt due within one year and current portion of capital lease obligations.
(4)	SDG&E redeemed all series of its outstanding shares of contingently redeemable stock in 2013, as we discuss in Note 11 of the Notes to Consolidated Financial Statements.

In June 2013, SDG&E recorded a $200 million pretax loss from plant closure related to its investment in SONGS.

We discuss the impact of natural gas prices on revenues in 2015, 2014 and 2013 in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Changes in Revenues, Costs and Earnings.” We do not provide per-share data for SDG&E and SoCalGas because their common stock is indirectly wholly owned by Sempra Energy.

We discuss litigation and other contingencies in Note 15 of the Notes to Consolidated Financial Statements.

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, 2015, 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 (2013) 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, 2015. Deloitte & Touche LLP audited the effectiveness of each company’s internal control over financial reporting as of December 31, 2015, 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

None.

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, 2015, based on criteria established in Internal Control — Integrated Framework (2013) 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, 2015, based on the criteria established in Internal Control — Integrated Framework (2013) 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, 2015 of the Company and our report dated February 26, 2016 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2016

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, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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, 2015, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2016 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2016

SAN DIEGO GAS & ELECTRIC COMPANY

To the Board of Directors and Shareholder 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, 2015, based on criteria established in Internal Control — Integrated Framework (2013) 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, 2016

To the Board of Directors and Shareholder 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, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2015. 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, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2016

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, 2015, based on criteria established in Internal Control — Integrated Framework (2013) 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, 2016

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, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2016

SEMPRA ENERGY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts)
	Years ended December 31,
	2015			2014			2013

REVENUES
Utilities	$	9,254		$	9,758		$	9,309
Energy-related businesses		977			1,277			1,248
Total revenues		10,231			11,035			10,557
EXPENSES AND OTHER INCOME
Utilities:
Cost of natural gas		(1,134	)		(1,758	)		(1,646	)
Cost of electric fuel and purchased power		(2,136	)		(2,281	)		(1,932	)
Energy-related businesses:
Cost of natural gas, electric fuel and purchased power		(335	)		(552	)		(435	)
Other cost of sales		(148	)		(163	)		(178	)
Operation and maintenance		(2,895	)		(2,935	)		(2,995	)
Depreciation and amortization		(1,250	)		(1,156	)		(1,113	)
Franchise fees and other taxes		(423	)		(408	)		(374	)
Plant closure adjustment (loss)		26			(6	)		(200	)
Gain on sale of equity interests and assets		70			62			114
Equity earnings, before income tax		104			81			31
Other income, net		126			137			140
Interest income		29			22			20
Interest expense		(561	)		(554	)		(559	)
Income before income taxes and equity earnings
of certain unconsolidated subsidiaries		1,704			1,524			1,430
Income tax expense		(341	)		(300	)		(366	)
Equity earnings, net of income tax		85			38			24
Net income		1,448			1,262			1,088
Earnings attributable to noncontrolling interests		(98	)		(100	)		(79	)
Call premium on preferred stock of subsidiary		―			―			(3	)
Preferred dividends of subsidiaries		(1	)		(1	)		(5	)
Earnings	$	1,349		$	1,161		$	1,001


Basic earnings per common share	$	5.43		$	4.72		$	4.10
Weighted-average number of shares outstanding, basic (thousands)		248,249			245,891			243,863

Diluted earnings per common share	$	5.37		$	4.63		$	4.01
Weighted-average number of shares outstanding, diluted (thousands)		250,923			250,655			249,332

See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31, 2015, 2014 and 2013
	Sempra Energy shareholders' equity
	Pretax			Income tax			Net-of-tax			Noncontrolling
	amount			(expense) benefit			amount			interests (after-tax)			Total
2015:
Net income	$	1,691		$	(341	)	$	1,350		$	98		$	1,448
Other comprehensive income (loss):
Foreign currency translation adjustments		(260	)		―			(260	)		(30	)		(290	)
Financial instruments		(80	)		33			(47	)		5			(42	)
Pension and other postretirement benefits		(3	)		1			(2	)		―			(2	)
Total other comprehensive loss		(343	)		34			(309	)		(25	)		(334	)
Comprehensive income		1,348			(307	)		1,041			73			1,114
Preferred dividends of subsidiary		(1	)		―			(1	)		―			(1	)
Comprehensive income, after
preferred dividends of subsidiary	$	1,347		$	(307	)	$	1,040		$	73		$	1,113
2014:
Net income	$	1,462		$	(300	)	$	1,162		$	100		$	1,262
Other comprehensive income (loss):
Foreign currency translation adjustments		(193	)		―			(193	)		(20	)		(213	)
Financial instruments		(106	)		42			(64	)		(1	)		(65	)
Pension and other postretirement benefits		(20	)		8			(12	)		―			(12	)
Total other comprehensive loss		(319	)		50			(269	)		(21	)		(290	)
Comprehensive income		1,143			(250	)		893			79			972
Preferred dividends of subsidiary		(1	)		―			(1	)		―			(1	)
Comprehensive income, after
preferred dividends of subsidiary	$	1,142		$	(250	)	$	892		$	79		$	971
2013:
Net income	$	1,375		$	(366	)	$	1,009		$	79		$	1,088
Other comprehensive income (loss):
Foreign currency translation adjustments		111			―			111			(27	)		84
Financial instruments		13			(4	)		9			19			28
Pension and other postretirement benefits		47			(19	)		28			―			28
Total other comprehensive income (loss)		171			(23	)		148			(8	)		140
Comprehensive income		1,546			(389	)		1,157			71			1,228
Preferred dividends of subsidiaries		(5	)		―			(5	)		―			(5	)
Comprehensive income, after
preferred dividends of subsidiaries	$	1,541		$	(389	)	$	1,152		$	71		$	1,223

See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31,			December 31,
	2015			2014(1)
ASSETS
Current assets:
Cash and cash equivalents	$	403		$	570
Restricted cash		27			11
Trade accounts receivable, net		1,283			1,242
Other accounts receivable, net		190			152
Due from unconsolidated affiliates		6			38
Income taxes receivable		30			45
Deferred income taxes		―			305
Inventories		298			396
Regulatory balancing accounts – undercollected		307			746
Fixed-price contracts and other derivatives		80			93
Asset held for sale, power plant		―			293
Other		267			293
Total current assets		2,891			4,184

Investments and other assets:
Restricted cash		20			29
Due from unconsolidated affiliates		186			188
Regulatory assets		3,273			3,031
Nuclear decommissioning trusts		1,063			1,131
Investments		2,905			2,848
Goodwill		819			931
Other intangible assets		404			415
Dedicated assets in support of certain benefit plans		464			512
Insurance receivable for Aliso Canyon costs		325			―
Sundry		761			480
Total investments and other assets		10,220			9,565

Property, plant and equipment:
Property, plant and equipment		38,200			35,407
Less accumulated depreciation and amortization		(10,161	)		(9,505	)
Property, plant and equipment, net ($383 and $410 at December 31, 2015 and
2014, respectively, related to VIE)		28,039			25,902
Total assets	$	41,150		$	39,651

(1)	As adjusted for the retrospective adoption of ASU 2015-03.
See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	December 31,			December 31,
	2015			2014(1)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$	622		$	1,733
Accounts payable – trade		1,133			1,198
Accounts payable – other		142			155
Due to unconsolidated affiliates		14			2
Dividends and interest payable		303			282
Accrued compensation and benefits		423			373
Regulatory balancing accounts – overcollected		34			―
Current portion of long-term debt		907			469
Fixed-price contracts and other derivatives		56			55
Customer deposits		153			153
Reserve for Aliso Canyon costs		274			―
Other		551			649
Total current liabilities		4,612			5,069

Long-term debt ($303 and $312 at December 31, 2015 and 2014, respectively,
related to VIE)		13,134			12,086

Deferred credits and other liabilities:
Customer advances for construction		149			144
Pension and other postretirement benefit plan obligations, net of plan assets		1,152			1,064
Deferred income taxes		3,157			3,003
Deferred investment tax credits		32			37
Regulatory liabilities arising from removal obligations		2,793			2,741
Asset retirement obligations		2,126			2,048
Fixed-price contracts and other derivatives		240			255
Deferred credits and other		1,176			1,104
Total deferred credits and other liabilities		10,825			10,396

Commitments and contingencies (Note 15)

Equity:
Preferred stock (50 million shares authorized; none issued)		―			―
Common stock (750 million shares authorized; 248 million and 246 million
shares outstanding at December 31, 2015 and 2014, respectively; no par value)		2,621			2,484
Retained earnings		9,994			9,339
Accumulated other comprehensive income (loss)		(806	)		(497	)
Total Sempra Energy shareholders’ equity		11,809			11,326
Preferred stock of subsidiary		20			20
Other noncontrolling interests		750			754
Total equity		12,579			12,100
Total liabilities and equity	$	41,150		$	39,651

(1)	As adjusted for the retrospective adoption of ASU 2015-03.
See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,448		$	1,262		$	1,088
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		1,250			1,156			1,113
Deferred income taxes and investment tax credits		239			146			334
Gain on sale of equity interests and assets		(70	)		(62	)		(114	)
Plant closure (adjustment) loss		(26	)		6			200
Equity earnings		(189	)		(119	)		(55	)
Fixed-price contracts and other derivatives		(10	)		(25	)		(21	)
Other		75			108			13
Net change in other working capital components		699			(375	)		(620	)
Insurance receivable for Aliso Canyon costs		(325	)		―			―
Changes in other assets		(162	)		19			(171	)
Changes in other liabilities		(24	)		45			17
Net cash provided by operating activities		2,905			2,161			1,784

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(3,156	)		(3,123	)		(2,572	)
Expenditures for investments and acquisition of businesses		(200	)		(240	)		(22	)
Proceeds from sale of equity interests and assets, net of cash sold		373			149			570
Proceeds from U.S. Treasury grants		―			―			238
Distributions from investments		15			13			152
Proceeds from sales by nuclear decommissioning and other trusts		577			601			695
Purchases of nuclear decommissioning and other trust assets		(531	)		(613	)		(697	)
Increases in restricted cash		(100	)		(152	)		(356	)
Decreases in restricted cash		93			155			329
Advances to unconsolidated affiliates		(31	)		(185	)		(14	)
Repayments of advances to unconsolidated affiliates		74			18			―
Other		1			35			(12	)
Net cash used in investing activities		(2,885	)		(3,342	)		(1,689	)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(628	)		(598	)		(606	)
Redemption of preferred stock of subsidiary		―			―			(82	)
Preferred dividends paid by subsidiaries		(1	)		(1	)		(5	)
Issuances of common stock		52			56			62
Repurchases of common stock		(74	)		(38	)		(45	)
Issuances of debt (maturities greater than 90 days)		2,992			3,272			2,081
Payments on debt (maturities greater than 90 days)		(1,854	)		(2,034	)		(1,788	)
Proceeds from sale of noncontrolling interests, net of $25 in offering costs		―			―			574
(Decrease) increase in short-term debt, net		(622	)		412			256
Purchase of noncontrolling interests		―			(74	)		―
Net distributions to noncontrolling interests		(73	)		(104	)		(69	)
Tax benefit related to share-based compensation		52			―			―
Other		(17	)		(37	)		(40	)
Net cash (used in) provided by financing activities		(173	)		854			338
Effect of exchange rate changes on cash and cash equivalents		(14	)		(7	)		(4	)

(Decrease) increase in cash and cash equivalents		(167	)		(334	)		429
Cash and cash equivalents, January 1		570			904			475
Cash and cash equivalents, December 31	$	403		$	570		$	904
See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
CHANGES IN OTHER WORKING CAPITAL COMPONENTS
(Excluding cash and cash equivalents, and debt due within one year)
Accounts receivable	$	(99	)	$	44		$	(273	)
Income taxes receivable, net		39			62			(38	)
Inventories		65			(133	)		116
Regulatory balancing accounts		586			(317	)		(198	)
Regulatory assets and liabilities		(4	)		8			1
Other current assets		(18	)		(10	)		15
Accounts payable		(157	)		109			(28	)
Reserve for Aliso Canyon costs		274			―			―
Other current liabilities		13			(138	)		(215	)
Net change in other working capital components	$	699		$	(375	)	$	(620	)

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	537		$	536		$	544
Income tax payments, net of refunds		67			102			120

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Acquisition of businesses:
Assets acquired	$	10		$	―		$	13
Liabilities assumed		(2	)		―			(2	)
Accrued purchase price		(5	)		―			―
Cash paid	$	3		$	―		$	11

Nuclear facility plant reclassified to regulatory asset, net of depreciation and amortization	$	―		$	―		$	512
Accrued capital expenditures		566			433			437
Increase in capital lease obligations for investment in property, plant and equipment		24			60			―
Financing of build-to-suit property		61			61			14
Capital expenditures recoverable by U.S. Treasury grants receivable		―			―			3
Sequestration of U.S. Treasury grants receivable		―			―			(23	)
Redemption of industrial development bonds		79			―			―
Common dividends issued in stock		55			42			―
Dividends declared but not paid		180			166			157

See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Dollars in millions)
	Years ended December 31, 2015, 2014 and 2013
							Accumulated			Sempra
							other			Energy			Non-
	Common			Retained			comprehensive			shareholders’			controlling			Total
	stock			earnings			income (loss)			equity			interests			equity
Balance at December 31, 2012	$	2,217		$	8,441		$	(376	)	$	10,282		$	401		$	10,683

Net income					1,009						1,009			79			1,088
Other comprehensive income (loss)								148			148			(8	)		140

Share-based compensation expense		40									40						40
Common stock dividends declared					(615	)					(615	)					(615	)
Preferred dividends of subsidiaries					(5	)					(5	)					(5	)
Issuances of common stock		62									62						62
Repurchases of common stock		(45	)								(45	)					(45	)
Sale of noncontrolling interests, net of
offering costs		135									135			439			574
Distributions to noncontrolling interests														(69	)		(69	)
Call premium on preferred stock
of subsidiary					(3	)					(3	)					(3	)
Balance at December 31, 2013		2,409			8,827			(228	)		11,008			842			11,850

Net income					1,162						1,162			100			1,262
Other comprehensive loss								(269	)		(269	)		(21	)		(290	)

Share-based compensation expense		48									48						48
Common stock dividends declared					(649	)					(649	)					(649	)
Preferred dividends of subsidiary					(1	)					(1	)					(1	)
Issuances of common stock		97									97						97
Repurchases of common stock		(38	)								(38	)					(38	)
Distributions to noncontrolling interests														(107	)		(107	)
Equity contributed by noncontrolling
interests														1			1
Purchase of noncontrolling interests in
subsidiary		(32	)								(32	)		(41	)		(73	)
Balance at December 31, 2014		2,484			9,339			(497	)		11,326			774			12,100

Net income					1,350						1,350			98			1,448
Other comprehensive loss								(309	)		(309	)		(25	)		(334	)

Share-based compensation expense		52									52						52
Common stock dividends declared					(694	)					(694	)					(694	)
Preferred dividends of subsidiary					(1	)					(1	)					(1	)
Issuances of common stock		107									107						107
Repurchases of common stock		(74	)								(74	)					(74	)
Tax benefit related to share-based
compensation		52									52						52
Distributions to noncontrolling interests														(80	)		(80	)
Equity contributed by noncontrolling
interests														3			3
Balance at December 31, 2015	$	2,621		$	9,994		$	(806	)	$	11,809		$	770		$	12,579

See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Operating revenues
Electric	$	3,719		$	3,785		$	3,537
Natural gas		500			544			529
Total operating revenues		4,219			4,329			4,066
Operating expenses
Cost of electric fuel and purchased power		1,151			1,309			1,019
Cost of natural gas		153			208			204
Operation and maintenance		1,017			1,076			1,157
Depreciation and amortization		604			530			494
Franchise fees and other taxes		262			241			210
Plant closure (adjustment) loss		(26	)		6			200
Total operating expenses		3,161			3,370			3,284
Operating income		1,058			959			782
Other income, net		36			40			40
Interest income		―			―			1
Interest expense		(204	)		(202	)		(197	)
Income before income taxes		890			797			626
Income tax expense		(284	)		(270	)		(191	)
Net income		606			527			435
Earnings attributable to noncontrolling interest		(19	)		(20	)		(24	)
Earnings		587			507			411
Call premium on preferred stock		―			―			(3	)
Preferred dividend requirements		―			―			(4	)
Earnings attributable to common shares	$	587		$	507		$	404

See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31, 2015, 2014 and 2013
	SDG&E shareholder's equity
	Pretax			Income tax			Net-of-tax			Noncontrolling
	amount			(expense) benefit			amount			interest (after-tax)		Total
2015:
Net income	$	871		$	(284	)	$	587		$	19	$	606
Other comprehensive income (loss):
Financial instruments		―			―			―			6		6
Pension and other postretirement benefits		7			(3	)		4			―		4
Total other comprehensive income		7			(3	)		4			6		10
Comprehensive income	$	878		$	(287	)	$	591		$	25	$	616
2014:
Net income	$	777		$	(270	)	$	507		$	20	$	527
Other comprehensive income (loss):
Financial instruments		―			―			―			2		2
Pension and other postretirement benefits		(5	)		2			(3	)		―		(3	)
Total other comprehensive (loss) income		(5	)		2			(3	)		2		(1	)
Comprehensive income	$	772		$	(268	)	$	504		$	22	$	526
2013:
Net income	$	602		$	(191	)	$	411		$	24	$	435
Other comprehensive income (loss):
Financial instruments		―			―			―			17		17
Pension and other postretirement benefits		3			(1	)		2			―		2
Total other comprehensive income		3			(1	)		2			17		19
Comprehensive income	$	605		$	(192	)	$	413		$	41	$	454

See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31,			December 31,
	2015			2014(1)
ASSETS
Current assets:
Cash and cash equivalents	$	20		$	8
Restricted cash		23			8
Accounts receivable – trade, net		331			285
Accounts receivable – other, net		17			35
Due from unconsolidated affiliates		1			1
Inventories		75			73
Regulatory balancing accounts – net undercollected		307			711
Regulatory assets		107			54
Fixed-price contracts and other derivatives		53			44
Other		70			125
Total current assets		1,004			1,344

Other assets:
Restricted cash		―			11
Deferred taxes recoverable in rates		914			824
Other regulatory assets		977			1,086
Nuclear decommissioning trusts		1,063			1,131
Sundry		301			246
Total other assets		3,255			3,298

Property, plant and equipment:
Property, plant and equipment		16,458			15,478
Less accumulated depreciation and amortization		(4,202	)		(3,860	)
Property, plant and equipment, net ($383 and $410 at December 31, 2015
and 2014, respectively, related to VIE)		12,256			11,618
Total assets	$	16,515		$	16,260

(1)	As adjusted for the retrospective adoption of ASU 2015-03.
See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	December 31,			December 31,
	2015			2014(1)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$	168		$	246
Accounts payable		377			441
Due to unconsolidated affiliates		55			21
Income taxes payable		―			30
Deferred income taxes		―			53
Interest payable		39			40
Accrued compensation and benefits		129			124
Accrued franchise fees		66			71
Current portion of long-term debt		50			365
Asset retirement obligations		99			120
Fixed-price contracts and other derivatives		51			40
Customer deposits		72			71
Other		101			166
Total current liabilities		1,207			1,788
Long-term debt ($303 and $312 at December 31, 2015 and 2014, respectively,
related to VIE)		4,455			4,283

Deferred credits and other liabilities:
Customer advances for construction		46			41
Pension and other postretirement benefit plan obligations, net of plan assets		212			216
Deferred income taxes		2,472			2,121
Deferred investment tax credits		19			22
Regulatory liabilities arising from removal obligations		1,629			1,557
Asset retirement obligations		729			754
Fixed-price contracts and other derivatives		106			153
Deferred credits and other		364			333
Total deferred credits and other liabilities		5,577			5,197

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		3,893			3,606
Accumulated other comprehensive income (loss)		(8	)		(12	)
Total SDG&E shareholder’s equity		5,223			4,932
Noncontrolling interest		53			60
Total equity		5,276			4,992
Total liabilities and equity	$	16,515		$	16,260

(1)	As adjusted for the retrospective adoption of ASU 2015-03.
See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	606		$	527		$	435
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		604			530			494
Deferred income taxes and investment tax credits		195			223			171
Plant closure (adjustment) loss		(26	)		6			200
Fixed-price contracts and other derivatives		(4	)		(6	)		(8	)
Other		(16	)		(23	)		(37	)
Changes in other assets		(122	)		191			(150	)
Changes in other liabilities		13			18			19
Changes in working capital components:
Accounts receivable		(10	)		(47	)		(40	)
Due to/from affiliates, net		21			(10	)		38
Inventories		(2	)		4			(14	)
Other current assets		(24	)		(16	)		7
Income taxes		―			35			(50	)
Accounts payable		(28	)		(23	)		50
Regulatory balancing accounts		474			(208	)		(140	)
Interest payable		(1	)		―			4
Other current liabilities		(16	)		(104	)		(260	)
Net cash provided by operating activities		1,664			1,097			719

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(1,133	)		(1,100	)		(978	)
Proceeds from sales by nuclear decommissioning trusts		577			601			685
Purchases of nuclear decommissioning trust assets		(526	)		(609	)		(692	)
Proceeds from sale of assets		―			―			11
Increase in restricted cash		(39	)		(84	)		(81	)
Decrease in restricted cash		35			96			82
Expenditures related to long-term service agreement		―			(30	)		―
Net cash used in investing activities		(1,086	)		(1,126	)		(973	)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(300	)		(200	)		―
Redemption of preferred stock		―			―			(82	)
Preferred dividends paid		―			―			(5	)
Issuances of debt (maturities greater than 90 days)		444			100			450
Payments on debt (maturities greater than 90 days)		(547	)		(24	)		(199	)
(Decrease) increase in short-term debt, net		(131	)		187			59
Capital distributions made by Otay Mesa VIE		(30	)		(53	)		(26	)
Other		(2	)		―			(3	)
Net cash (used in) provided by financing activities		(566	)		10			194
Increase (decrease) in cash and cash equivalents		12			(19	)		(60	)
Cash and cash equivalents, January 1		8			27			87
Cash and cash equivalents, December 31	$	20		$	8		$	27

See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
	Years ended December 31,
	2015			2014				2013
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized		$	199		$	196			$	187
Income tax payments (refunds), net			88			(4	)			84

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Nuclear facility plant reclassified to regulatory asset, net of depreciation and amortization		$	―		$	―			$	512
Accrued capital expenditures			191			217				182
Increase in capital lease obligations for investment in property, plant and equipment			15			60				―

See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Dollars in millions)
	Years ended December 31, 2015, 2014 and 2013
						Accumulated
						other			SDG&E
	Common		Retained			comprehensive			shareholder’s			Noncontrolling			Total
	stock		earnings			income (loss)			equity			interest			equity
Balance at December 31, 2012	$	1,338	$	2,895		$	(11	)	$	4,222		$	76		$	4,298

Net income				411						411			24			435
Other comprehensive income							2			2			17			19

Preferred stock dividends declared				(4	)					(4	)					(4	)
Distributions to noncontrolling interest													(26	)		(26	)
Call premium on preferred stock				(3	)					(3	)					(3	)
Balance at December 31, 2013		1,338		3,299			(9	)		4,628			91			4,719

Net income				507						507			20			527
Other comprehensive (loss) income							(3	)		(3	)		2			(1	)

Common stock dividends declared				(200	)					(200	)					(200	)
Distributions to noncontrolling interest													(53	)		(53	)
Balance at December 31, 2014		1,338		3,606			(12	)		4,932			60			4,992

Net income				587						587			19			606
Other comprehensive income							4			4			6			10

Common stock dividends declared				(300	)					(300	)					(300	)
Distributions to noncontrolling interest													(32	)		(32	)
Balance at December 31, 2015	$	1,338	$	3,893		$	(8	)	$	5,223		$	53		$	5,276

See Notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013

Operating revenues	$	3,489		$	3,855		$	3,736
Operating expenses
Cost of natural gas		921			1,449			1,362
Operation and maintenance		1,370			1,321			1,324
Depreciation and amortization		461			431			383
Franchise fees and other taxes		129			133			128
Total operating expenses		2,881			3,334			3,197
Operating income		608			521			539
Other income, net		30			20			11
Interest income		4			―			―
Interest expense		(84	)		(69	)		(69	)
Income before income taxes		558			472			481
Income tax expense		(138	)		(139	)		(116	)
Net income		420			333			365
Preferred dividend requirements		(1	)		(1	)		(1	)
Earnings attributable to common shares	$	419		$	332		$	364

See Notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31, 2015, 2014 and 2013
	Pretax			Income tax			Net-of-tax
	amount			(expense) benefit			amount
2015:
Net income	$	558		$	(138	)	$	420
Other comprehensive income (loss):
Financial instruments		1			(1	)		―
Pension and other postretirement benefits		(2	)		1			(1	)
Total other comprehensive loss		(1	)		―			(1	)
Comprehensive income	$	557		$	(138	)	$	419
2014:
Net income/Comprehensive income	$	472		$	(139	)	$	333
2013:
Net income	$	481		$	(116	)	$	365
Other comprehensive income (loss):
Financial instruments		1			―			1
Pension and other postretirement benefits		(2	)		1			(1	)
Total other comprehensive loss		(1	)		1			―
Comprehensive income	$	480		$	(115	)	$	365

See Notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31,			December 31,
	2015			2014(1)
ASSETS
Current assets:
Cash and cash equivalents	$	58		$	85
Accounts receivable – trade, net		635			586
Accounts receivable – other, net		99			51
Due from unconsolidated affiliates		48			4
Income taxes receivable		―			5
Inventories		79			181
Regulatory balancing accounts – net undercollected		―			35
Regulatory assets		7			5
Other		40			36
Total current assets		966			988

Other assets:
Regulatory assets arising from pension obligations		699			617
Other regulatory assets		636			472
Insurance receivable for Aliso Canyon costs		325			―
Sundry		207			125
Total other assets		1,867			1,214

Property, plant and equipment:
Property, plant and equipment		14,171			12,886
Less accumulated depreciation and amortization		(4,900	)		(4,642	)
Property, plant and equipment, net		9,271			8,244
Total assets	$	12,104		$	10,446

(1)	As adjusted for the retrospective adoption of ASU 2015-03.
See Notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	December 31,			December 31,
	2015			2014(1)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term debt	$	―		$	50
Accounts payable – trade		422			532
Accounts payable – other		76			88
Due to unconsolidated affiliate		―			13
Income taxes payable		3			―
Deferred income taxes		―			53
Accrued compensation and benefits		160			129
Regulatory balancing accounts – net overcollected		34			―
Current portion of long-term debt		9			―
Customer deposits		76			75
Reserve for Aliso Canyon costs		274			―
Other		184			149
Total current liabilities		1,238			1,089

Long-term debt		2,481			1,891
Deferred credits and other liabilities:
Customer advances for construction		103			102
Pension obligation, net of plan assets		716			633
Deferred income taxes		1,532			1,212
Deferred investment tax credits		14			16
Regulatory liabilities arising from removal obligations		1,145			1,167
Asset retirement obligations		1,354			1,255
Deferred credits and other		372			300
Total deferred credits and other liabilities		5,236			4,685

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		2,280			1,911
Accumulated other comprehensive income (loss)		(19	)		(18	)
Total shareholders’ equity		3,149			2,781
Total liabilities and shareholders’ equity	$	12,104		$	10,446

(1)	As adjusted for the retrospective adoption of ASU 2015-03.
See Notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	420		$	333		$	365
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		461			431			383
Deferred income taxes and investment tax credits		127			130			117
Other		(11	)		(7	)		(5	)
Insurance receivable for Aliso Canyon costs		(325	)		―			―
Changes in other assets		(91	)		(131	)		(52	)
Changes in other liabilities		(7	)		29			(4	)
Changes in working capital components:
Accounts receivable		(90	)		30			(113	)
Inventories		102			(113	)		82
Other current assets		8			(3	)		3
Accounts payable		(143	)		156			(54	)
Income taxes		8			17			51
Due to/from affiliates, net		(11	)		(1	)		(57	)
Regulatory balancing accounts		112			(109	)		(58	)
Customer deposits		1			―			(1	)
Reserve for Aliso Canyon costs		274			―			―
Other current liabilities		45			3			24
Net cash provided by operating activities		880			765			681

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(1,352	)		(1,104	)		(762	)
(Increase) decrease in loans to affiliate, net		(50	)		―			34
Net cash used in investing activities		(1,402	)		(1,104	)		(728	)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(50	)		(100	)		(50	)
Preferred dividends paid		(1	)		(1	)		(1	)
Issuances of long-term debt		599			747			―
Payments on long-term debt		―			(250	)		―
Debt issuance costs		(3	)		(7	)		―
(Decrease) increase in short-term debt, net		(50	)		8			42
Net cash provided by (used in) financing activities		495			397			(9	)

(Decrease) increase in cash and cash equivalents		(27	)		58			(56	)
Cash and cash equivalents, January 1		85			27			83
Cash and cash equivalents, December 31	$	58		$	85		$	27

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	79		$	62		$	65
Income tax payments (refunds), net		1			(10	)		(52	)

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY
Accrued capital expenditures	$	189		$	168		$	130

See Notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Dollars in millions)
	Years ended December 31, 2015, 2014 and 2013
								Accumulated
								other			Total
	Preferred		Common		Retained			comprehensive			shareholders’
	stock		stock		earnings			income (loss)			equity
Balance at December 31, 2012	$	22	$	866	$	1,365		$	(18	)	$	2,235

Net income						365						365

Preferred stock dividends declared						(1	)					(1	)
Common stock dividends declared						(50	)					(50	)
Balance at December 31, 2013		22		866		1,679			(18	)		2,549

Net income						333						333

Preferred stock dividends declared						(1	)					(1	)
Common stock dividends declared						(100	)					(100	)
Balance at December 31, 2014		22		866		1,911			(18	)		2,781

Net income						420						420
Other comprehensive loss									(1	)		(1	)

Preferred stock dividends declared						(1	)					(1	)
Common stock dividends declared						(50	)					(50	)
Balance at December 31, 2015	$	22	$	866	$	2,280		$	(19	)	$	3,149

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 energy-services 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.

Our Sempra Mexico segment includes the operating companies of our subsidiary, Infraestructura Energética Nova, S.A.B. de C.V. (IEnova), as well as certain holding companies and risk management activity. We discuss IEnova below under “Noncontrolling Interests – Sale of Noncontrolling Interests.”

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 entities in Notes 3, 4 and 10.

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 accounts and the de minimis accounts of inactive subsidiaries. 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, Chilquinta Energía S.A. (Chilquinta Energía) in Chile and Luz del Sur S.A.A. (Luz del Sur) in Peru and their subsidiaries. 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 México, S. de R.L. de C.V. (Ecogas) in northern Mexico, all natural gas distribution utilities. The California Utilities, Mobile Gas, Willmut Gas, and Ecogas prepare their financial statements in accordance with the provisions of accounting principles generally accepted in the United States of America (U.S. GAAP) governing rate-regulated operations, as we discuss below under “Regulatory Matters.” We discuss revenue recognition at our utilities in “Revenues – Utilities” below.

Pipeline projects currently under construction by IEnova that are both regulated by the Comisión Reguladora de Energía (or CRE, the Energy Regulatory Commission) and meet the regulatory accounting requirements of U.S. GAAP record the impact of allowance for funds used during construction (AFUDC) related to equity. We discuss AFUDC below.

Use of Estimates in the Preparation of the Financial Statements

We have prepared our Consolidated Financial Statements in conformity with 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, 2015 through the date the financial statements were issued, and in the opinion of management, the accompanying statements reflect all adjustments and disclosures necessary for a fair presentation.

REGULATORY MATTERS

Effects of Regulation

The accounting policies of the California Utilities conform with U.S. GAAP for rate-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 rate-regulated operations. Under these provisions, a regulated utility records regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover those assets 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 that 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 precedents;

§	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.

Mobile Gas, Willmut Gas and Ecogas also apply U.S. GAAP for rate-regulated utilities to their operations, including the same evaluation of probability of recovery of regulatory assets described above.

We provide information concerning regulatory assets and liabilities below in “Regulatory Balancing Accounts” and “Regulatory Assets and Liabilities” and in Notes 13 and 14.

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
	2015				2014				2015				2014				2015				2014
Current:
Overcollected		$	(1,200	)		$	(1,730	)		$	(756	)		$	(1,195	)		$	(444	)		$	(535	)
Undercollected			1,473				2,476				1,063				1,906				410				570
Net current receivable (payable)(1)			273				746				307				711				(34	)			35
Noncurrent:
Undercollected(2)			215				173				―				―				215				173
Total net receivable		$	488			$	919			$	307			$	711			$	181			$	208

(1)

At December 31, 2015, the net receivable at SDG&E and the net payable at SoCalGas are shown separately on Sempra Energy's Consolidated Balance Sheet.

(2)

Long-term undercollected balance is included in Regulatory Assets (long-term) on Sempra Energy's Consolidated Balance Sheets and Other Regulatory Assets (long-term) on SoCalGas' Consolidated Balance Sheets.

Over- and undercollected 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 13, 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)
	2015			2014
SDG&E:
Fixed-price contracts and other derivatives	$	99		$	76
Costs related to SONGS plant closure(1)		257			308
Costs related to wildfire litigation		362			373
Deferred taxes recoverable in rates		914			824
Pension and other postretirement benefit plan obligations		180			171
Removal obligations(2)		(1,629	)		(1,557	)
Unamortized loss on reacquired debt		12			12
Environmental costs		16			27
Legacy meters(1)		32			47
Sunrise Powerlink fire mitigation		117			116
Other		9			10
Total SDG&E		369			407
SoCalGas:
Pension and other postretirement benefit plan obligations		629			613
Employee benefit costs		51			52
Removal obligations(2)		(1,145	)		(1,167	)
Deferred taxes recoverable in rates		330			195
Unamortized loss on reacquired debt		11			12
Environmental costs		22			22
Workers’ compensation		13			23
Total SoCalGas		(89	)		(250	)
Other Sempra Energy:
Sempra Natural Gas		(7	)		(17	)
Sempra Mexico		33			23
Total Other Sempra Energy		26			6
Total Sempra Energy Consolidated	$	306		$	163

(1)	Regulatory assets earning a rate of return.
(2)	Represents cumulative amounts collected in rates for future nonlegal asset removal costs.

NET REGULATORY ASSETS (LIABILITIES) AS PRESENTED ON THE CONSOLIDATED BALANCE SHEETS AT DECEMBER 31
(Dollars in millions)
	2015												2014
	Sempra												Sempra
	Energy												Energy
	Consolidated				SDG&E				SoCalGas				Consolidated				SDG&E				SoCalGas
Current regulatory assets(1)		$	115			$	107			$	7			$	59			$	54			$	5
Noncurrent regulatory assets(2)			3,058				1,891				1,120				2,858				1,910				916
Current regulatory liabilities(3)			(2	)			―				―				(7	)			―				―
Noncurrent regulatory liabilities(4)			(2,865	)			(1,629	)			(1,216	)			(2,747	)			(1,557	)			(1,171	)
Total		$	306			$	369			$	(89	)		$	163			$	407			$	(250	)

(1	)	At Sempra Energy Consolidated, included in Other Current Assets.
(2	)	Excludes long-term undercollected balancing accounts at December 31, 2015 and 2014 of $215 million and $173 million, respectively, recorded at Sempra Energy Consolidated as Regulatory Assets (long-term) and at SoCalGas as Other Regulatory Assets (long-term).
(3	)	Included in Other Current Liabilities.
(4	)	At December 31, 2015 and 2014, $72 million and $6 million, respectively, at Sempra Energy Consolidated and $71 million and $4 million, respectively, at SoCalGas are included in Deferred Credits and Other.

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 the San Onofre Nuclear Generating Station (SONGS) plant closure are associated with SDG&E’s investment in SONGS as of the plant closure date and the cost of operations since Units 2 and 3 were taken offline, as we discuss further in Note 13.

§	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 “SDG&E Matters – Wildfire Claims Cost Recovery” and Note 15 under “SDG&E – 2007 Wildfire Litigation.”

Deferred taxes recoverable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Mexico expect to recover net regulatory assets related to deferred income taxes over the lives of the assets that give rise to the accumulated deferred income tax liabilities. Regulatory assets include certain income tax benefits associated with flow-through repair allowance deductions, which we discuss further in “Joint Matters – CPUC General Rate Case (GRC) – 2016 General Rate Case (2016 GRC)” in Note 14.

§	Regulatory assets/liabilities related to pension and other postretirement benefit obligations are offset by corresponding liabilities/assets 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 amortization periods of the losses on reacquired debt. These periods range from 2 years to 12 years for SDG&E and from 6 years to 10 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 is recovering this asset over a remaining 2-year period in rate base.

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 remaining 54-year period. We discuss the trust further in Note 15.

§	The regulatory asset related to workers’ compensation represents accrued costs for future claims that will be recovered from customers in future rates as expenditures are made.

§	Amortization expense on regulatory assets for the years ended December 31, 2015, 2014 and 2013 was $62 million, $20 million and $28 million, respectively, at Sempra Energy Consolidated, $60 million, $18 million and $26 million, respectively, at SDG&E, and $2 million in each year at SoCalGas.

FAIR VALUE MEASUREMENTS

We apply recurring fair value measurements to certain assets and liabilities, primarily nuclear decommissioning and benefit plan trust assets and 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 domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the Nuclear Decommissioning Trusts and in our pension and postretirement benefit plans, 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. Our Level 3 financial instruments relate to congestion revenue rights (CRRs) and fixed-price electricity positions at SDG&E.

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 $47 million and $40 million at December 31, 2015 and 2014, respectively. Of this, $27 million and $11 million was classified as current and $20 million and $29 million was classified as noncurrent at December 31, 2015 and 2014, respectively.

SDG&E had $23 million and $19 million of restricted cash at December 31, 2015 and 2014, respectively, which represents funds held by a trustee for Otay Mesa VIE (see “Variable Interest Entities – SDG&E – Otay Mesa VIE” below) to pay certain operating costs. In 2015, all restricted cash was classified as current. In 2014, $8 million of restricted cash was classified as current and $11 million as noncurrent.

Sempra Mexico had restricted cash of $20 million and $18 million classified as noncurrent at December 31, 2015 and 2014, respectively, representing funds to pay for rights of way, license fees, permits, topographic surveys and other costs pursuant to trust agreements related to a pipeline project.

Sempra Renewables had restricted cash of $4 million and $3 million classified as current at December 31, 2015 and 2014, respectively, primarily representing funds held in accordance with debt agreements at Copper Mountain Solar 1.

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,
	2015			2014			2013
Sempra Energy Consolidated:
Allowances for collection of receivables at January 1	$	34		$	29		$	31
Provisions for uncollectible accounts		20			25			16
Write-offs of uncollectible accounts		(22	)		(20	)		(18	)
Allowances for collection of receivables at December 31	$	32		$	34		$	29
SDG&E:
Allowances for collection of receivables at January 1	$	7		$	5		$	6
Provisions for uncollectible accounts		7			7			4
Write-offs of uncollectible accounts		(5	)		(5	)		(5	)
Allowances for collection of receivables at December 31	$	9		$	7		$	5
SoCalGas:
Allowances for collection of receivables at January 1	$	17		$	12		$	14
Provisions for uncollectible accounts		11			15			7
Write-offs of uncollectible accounts		(11	)		(10	)		(9	)
Allowances for collection of receivables at December 31	$	17		$	17		$	12

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 net realizable value.

Sempra South American Utilities, Sempra Mexico and Sempra Natural Gas value natural gas inventory and materials and supplies at the lower of average cost or net realizable value. Sempra Mexico and Sempra Natural Gas 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
		2015			2014			2015	2014		2015		2014		2015			2014
SDG&E		$	6		$	8	$	―	$	―	$	69	$	65	$	75		$	73
SoCalGas			49	(1)		155		―		―		30		26		79	(1)		181
Sempra South American Utilities			―			―		―		―		30		33		30			33
Sempra Mexico			―			―		3		9		10		9		13			18
Sempra Renewables			―			―		―		―		3		2		3			2
Sempra Natural Gas			94			83		3		5		1		1		98			89
Sempra Energy Consolidated		$	149		$	246	$	6	$	14	$	143	$	136	$	298		$	396
(1)	As of December 31, 2015, SoCalGas recorded an estimated inventory loss related to the Aliso Canyon natural gas leak of $11 million, included in Insurance Receivable for Aliso Canyon Costs on Sempra Energy's and SoCalGas' Consolidated Balance Sheets. See additional discussion about the Aliso Canyon natural gas storage facility leak in Note 15.

U.S. TREASURY GRANTS

At December 31, 2012, we had receivables for U.S. Treasury grants based on eligible costs at certain of our renewable generating facilities. During the first quarter of 2013, the federal government imposed automatic federal budget cuts, known as “sequestration,” as required by The Budget Control Act of 2011. As a result, we recorded a reduction to our grants receivable of $23 million and a reversal of income tax benefit of $5 million during the first quarter of 2013. Later in 2013, we received $238 million in cash for the remaining grants receivable.

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 basis 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 and Sempra Mexico 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.

Except for the current year Peruvian earnings for which we have accrued U.S. income tax, we currently do not record deferred income taxes for basis differences between financial statement and income tax investment amounts in non-U.S. subsidiaries and non-U.S. joint ventures because the related 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 effective tax rate.

We provide additional information about income taxes in Note 6.

GREENHOUSE GAS (GHG) ALLOWANCES

The California Utilities, Sempra Mexico and Sempra Natural Gas are required by California Assembly Bill 32 to acquire GHG allowances for every metric ton of carbon dioxide equivalent emitted into the atmosphere during electric generation and natural gas transportation. We record GHG allowances at the lower of weighted average cost or market, and include them in Other Current Assets and Sundry on the Consolidated Balance Sheets based on the dates that they are required to be surrendered. We measure the compliance obligation, which is based on emissions, at the carrying value of allowances held plus the fair value of additional allowances necessary to satisfy the obligation. We include the obligation in Other Current Liabilities and Deferred Credits and Other on the Consolidated Balance Sheets based on the dates that the allowances will be surrendered. We remove the assets and liabilities from the balance sheets as the allowances are surrendered.

The California Utilities balance costs and revenues associated with the GHG program through Regulatory Balancing Accounts on the Consolidated Balance Sheets.

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 provide documentation for the generation of a unit of renewable energy that is used to verify compliance with renewable portfolio standards. The cost of RECs at SDG&E 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 in their operations, including construction work in progress at these operating units. Property, plant and equipment also includes lease improvements and other equipment at Parent and Other, as well as property acquired under a build-to-suit lease, which we discuss further in Note 15.

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 utility plant at our rate-regulated businesses and non-utility regulated projects that meet the regulatory accounting requirements of U.S. GAAP at Sempra Mexico and Sempra Natural Gas includes 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 assets less 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				Depreciation rates for
	and equipment at				years ended
	December 31,				December 31,
	2015		2014		2015			2014			2013
SDG&E:
Natural gas operations	$	1,642	$	1,535		2.52	%		2.72	%		2.35	%
Electric distribution		6,151		5,795		3.79			3.79			3.36
Electric transmission(1)		4,870		4,525		2.62			2.59			2.58
Electric generation(2)		1,891		1,862		3.89			3.86			3.76
Other electric(3)		981		851		5.73			7.09			7.58
Construction work in progress(1)		923		910	NA			NA			NA
Total SDG&E		16,458		15,478
SoCalGas:
Natural gas operations(4)		13,241		12,098		3.83			3.89			3.70
Other non-utility		110		120		3.95			2.88			1.56
Construction work in progress		820		668	NA			NA			NA
Total SoCalGas		14,171		12,886

					Estimated	Weighted average
Other operating units and parent(5):					useful lives	useful life
Land and land rights		289		290	26 to 55 years(6)		40
Machinery and equipment:
Utility electric distribution operations		1,362		1,434	12 to 46 years		43
Generating plants		782		596	5 to 80 years		39
LNG terminals		1,124		1,122	5 to 43 years		43
Pipelines and storage		2,311		2,003	3 to 55 years		45
Other		233		213	1 to 50 years		15
Construction work in progress		1,022		1,053	NA	NA
Other		448		332	2 to 80 years		35
		7,571		7,043
Total Sempra Energy Consolidated	$	38,200	$	35,407

(1)	At December 31, 2015, includes $374 million in electric transmission assets and $25 million in construction work in progress related to SDG&E's 91-percent interest in the Southwest Powerlink (SWPL) transmission line, jointly owned by SDG&E with other utilities. 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 its share of the project and participates in decisions concerning operations and capital expenditures.
(2)	Includes capital lease assets of $258 million and $243 million at December 31, 2015 and 2014, respectively, primarily related to variable interest entities of which SDG&E is not the primary beneficiary.
(3)	Includes capital lease assets of $20 million and $19 million at December 31, 2015 and 2014, respectively.
(4)	Includes capital lease assets of $30 million and $27 million at December 31, 2015 and 2014, respectively.
(5)	The December 31, 2015 balances include $142 million, $204 million and $28 million and the December 31, 2014 balances include $150 million, $191 million and $24 million of utility plant, primarily pipelines and other distribution assets, at Ecogas, Mobile Gas and Willmut Gas, respectively.
(6)	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. Depreciation expense on property, plant and equipment for Sempra Energy for the years ended December 31, 2015, 2014 and 2013 was $1,178 million, $1,126 million and $1,075 million, respectively. Depreciation expense on property, plant and equipment for SDG&E for the years ended December 31, 2015, 2014 and 2013 was $544 million, $512 million and $468 million, respectively. Depreciation expense on property, plant and equipment for SoCalGas for the years ended December 31, 2015, 2014 and 2013 was $459 million, $429 million and $381 million, respectively.

Accumulated depreciation on our Consolidated Balance Sheets is as follows:

ACCUMULATED DEPRECIATION
(Dollars in millions)
	December 31,
	2015		2014
SDG&E:
Accumulated depreciation:
Electric(1)	$	3,512	$	3,192
Natural gas		690		668
Total SDG&E		4,202		3,860
SoCalGas:
Accumulated depreciation of natural gas utility plant in service(2)		4,810		4,555
Accumulated depreciation – other non-utility		90		87
Total SoCalGas		4,900		4,642
Other operating units and parent and other:
Accumulated depreciation – other(3)		860		824
Accumulated depreciation of utility electric distribution operations		199		179
		1,059		1,003
Total Sempra Energy Consolidated	$	10,161	$	9,505

(1)	Includes accumulated depreciation for assets under capital lease of $34 million and $28 million at December 31, 2015 and 2014, respectively. Includes $224 million at December 31, 2015 related to SDG&E's 91-percent interest in the SWPL transmission line, jointly owned by SDG&E and other utilities.
(2)	Includes accumulated depreciation for assets under capital lease of $29 million and $27 million at December 31, 2015 and 2014, respectively.
(3)	The December 31, 2015 balances include $36 million, $35 million and $3 million and the December 31, 2014 balances include $37 million, $29 million and $2 million of accumulated depreciation for utility plant at Ecogas, Mobile Gas and Willmut 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.

Pipeline projects currently under construction by Sempra Mexico and Sempra Natural Gas that are both subject to certain regulation and meet U.S. GAAP regulatory accounting requirements record the impact of AFUDC related to equity. For the years ended December 31, 2015, 2014 and 2013, Sempra Mexico recorded AFUDC equity, mainly for its Sonora natural gas pipeline project, totaling $33 million, $43 million and $19 million, respectively. Sempra Natural Gas recorded AFUDC equity of $1 million in 2015, a negligible amount in 2014 and none in 2013.

Sempra International and Sempra U.S. Gas & Power businesses capitalize interest costs incurred to finance capital projects and interest on equity method investments that have not commenced planned principal operations. The California Utilities also capitalize certain interest costs.

CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Years ended December 31,
	2015		2014		2013
Sempra Energy Consolidated:
AFUDC related to debt	$	26	$	22	$	22
AFUDC related to equity		107		106		75
Other capitalized interest		68		39		22
Total Sempra Energy Consolidated	$	201	$	167	$	119
SDG&E:
AFUDC related to debt	$	14	$	15	$	16
AFUDC related to equity		37		37		39
Total SDG&E	$	51	$	52	$	55
SoCalGas:
AFUDC related to debt	$	12	$	7	$	6
AFUDC related to equity		36		26		17
Other capitalized interest		1		1		1
Total SoCalGas	$	49	$	34	$	24

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 we test it 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. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors, changes in key personnel and the overall financial performance of the reporting unit. If, after assessing these qualitative factors, we determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then we perform the two-step 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. We consider observable transactions in the marketplace for similar investments, if available, as well as 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

Changes in the carrying amount of goodwill on the Sempra Energy Consolidated Balance Sheets are as follows:

GOODWILL
(Dollars in millions)
		Sempra
	South American				Sempra		Sempra
		Utilities			Mexico		Natural Gas		Total
Balance at December 31, 2013		$	927		$	25	$	72	$	1,024
Foreign currency translation(1)			(93	)		―		―		(93	)
Balance at December 31, 2014			834			25		72		931
Foreign currency translation(1)			(112	)		―		―		(112	)
Balance at December 31, 2015		$	722		$	25	$	72	$	819

(1)

We record the offset of this fluctuation to other comprehensive income (loss).

Other Intangible Assets

Other Intangible Assets primarily 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), which are being amortized 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,
	(years)		2015			2014
Storage rights		46	$	138		$	138
Development rights		50		322			322
Other	10 years to indefinite			17			18
				477			478
Less accumulated amortization:
Storage rights				(22	)		(19	)
Development rights				(47	)		(40	)
Other				(4	)		(4	)
				(73	)		(63	)
			$	404		$	415

Amortization expense for intangible assets was $10 million in each of 2015, 2014 and 2013. 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

A long-lived asset is impaired when the estimated future undiscounted cash flows are less than the carrying amount of the asset. If that comparison indicates that the asset’s carrying value may not be recoverable, the impairment is measured based on the difference between the carrying amount and the fair value of the asset. 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

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.

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 a qualitative approach in which we consider 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.

Otay Mesa VIE

SDG&E has an agreement to purchase power generated at the Otay Mesa Energy Center (OMEC), a 605-megawatt (MW) generating facility. In addition to tolling, the agreement provides SDG&E with the option to purchase OMEC 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, holds no equity in OMEC LLC 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. Accordingly, SDG&E and Sempra Energy consolidate Otay Mesa VIE. Otay Mesa VIE’s equity of $53 million at December 31, 2015 and $60 million at December 31, 2014 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 $315 million at December 31, 2015, 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 9.

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 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,
	2015		2014(1)
Cash and cash equivalents	$	5	$	5
Restricted cash		23		8
Inventories		3		3
Other		―		1
Total current assets		31		17
Restricted cash		―		11
Property, plant and equipment, net		383		410
Total assets	$	414	$	438

Current portion of long-term debt	$	10	$	10
Fixed-price contracts and other derivatives		14		16
Other		5		3
Total current liabilities		29		29
Long-term debt		303		312
Fixed-price contracts and other derivatives		23		31
Deferred credits and other		6		6
Other noncontrolling interest		53		60
Total liabilities and equity	$	414	$	438

(1)

As adjusted for the retrospective adoption of ASU 2015-03, as we discuss in Note 2.

	Years ended December 31,
	2015				2014			2013
Operating expenses
Cost of electric fuel and purchased power		$	(83	)	$	(83	)	$	(91	)
Operation and maintenance			19			19			24
Depreciation and amortization			26			27			28
Total operating expenses			(38	)		(37	)		(39	)
Operating income			38			37			39
Interest expense			(19	)		(17	)		(15	)
Income before income taxes/Net income			19			20			24
Earnings attributable to noncontrolling interest			(19	)		(20	)		(24	)
Earnings attributable to common shares		$	―		$	―		$	―

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 at December 31, 2015. 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 Natural Gas

Sempra Energy’s equity method investment in Cameron LNG Holdings, LLC (Cameron LNG JV) is considered to be a VIE generally due to contractual provisions that transfer certain risks to customers. Sempra Energy is not the primary beneficiary because we do not have the power to direct the most significant activities of Cameron LNG JV. We will continue to evaluate Cameron LNG JV for any changes that may impact our determination of the primary beneficiary. The carrying value of our investment in Cameron LNG JV was $983 million at December 31, 2015, as we discuss in Note 4. Our maximum exposure to loss includes the carrying value of our investment and the guarantees discussed in Note 4.

Other Variable Interest Entities

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; however, their financial statements are not material to the financial statements of Sempra Energy. 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.

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 asset retirement cost (measured as the present value of the obligation at the time of the asset’s acquisition), and accreting the obligation until the liability is settled. Rate-regulated entities, including the California Utilities, 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 asset retirement obligations related to various assets, including:

SDG&E and SoCalGas

§	fuel and storage tanks

§	natural gas distribution systems

§	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 South American Utilities

§	electric distribution and transmission systems

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

§	natural gas distribution and transportation systems

§	underground natural gas storage facilities

§	power generation plant (natural gas) (sold in April 2015)

The changes in asset retirement obligations are as follows:

CHANGES IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
	Sempra Energy
	Consolidated								SDG&E								SoCalGas
	2015				2014				2015				2014				2015			2014
Balance as of January 1(1)		$	2,190			$	2,152			$	873			$	913			$	1,276		$	1,199
Accretion expense			92				97				40				43				49			52
Liabilities incurred			1				4				―				―				―			―
Reclassification(2)			―				(6	)			―				―				―			―
Payments(3)			(80	)			(29	)			(79	)			(29	)			―			―
Net revisions, other(4)			52				(28	)			(6	)			(54	)			58			25
Balance at December 31(1)		$	2,255			$	2,190			$	828			$	873			$	1,383		$	1,276

(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 Sheet at December 31, 2014.
(3	)	The increased payments at SDG&E are for the decommissioning of San Onofre Nuclear Generating Station Units 2 and 3, which we discuss in Note 13.
(4	)	The increases at SoCalGas in 2015 and 2014 are related to revisions in estimated cash flows. The decrease in 2014 at SDG&E is due to revised estimates in an updated decommissioning cost study for the San Onofre Nuclear Generating Station, which we discuss in Note 13.

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 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.

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 (loss) (OCI), including the amounts attributable to noncontrolling interests. The following tables present the changes in accumulated other comprehensive income (loss) (AOCI) by component and amounts reclassified out of AOCI to net income, excluding amounts attributable to noncontrolling interests, for the years ended December 31:


CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		Foreign				Pension		Total
		currency				and other		accumulated other
		translation		Financial		postretirement		comprehensive
		adjustments		instruments		benefits		income (loss)
Balance as of December 31, 2012		$	(240)	$	(35)	$	(101)	$	(376)

Other comprehensive (loss) income before
reclassifications			(159)		2		20		(137)
Amounts reclassified from accumulated other
comprehensive income			270	(2)	7		8		285
Net other comprehensive income			111		9		28		148
Balance as of December 31, 2013			(129)		(26)		(73)		(228)

Other comprehensive loss before
reclassifications			(193)		(70)		(26)		(289)
Amounts reclassified from accumulated other
comprehensive income			―		6		14		20
Net other comprehensive loss			(193)		(64)		(12)		(269)
Balance as of December 31, 2014			(322)		(90)		(85)		(497)

Other comprehensive loss before
reclassifications			(260)		(57)		(10)		(327)
Amounts reclassified from accumulated other
comprehensive income			―		10		8		18
Net other comprehensive loss			(260)		(47)		(2)		(309)
Balance as of December 31, 2015		$	(582)	$	(137)	$	(87)	$	(806)
(1)	All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.
(2)	Represents cumulative foreign currency translation adjustment related to the impairment of our Argentine investments in 2006, which is substantially offset by an accrued liability established at that time. We provide additional information about these investments in Note 4.

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SAN DIEGO GAS & ELECTRIC COMPANY
(Dollars in millions)
	Pension			Total
	and other			accumulated other
	postretirement			comprehensive
	benefits			income (loss)
Balance as of December 31, 2012	$	(11	)	$	(11	)

Amounts reclassified from accumulated other
comprehensive income		2			2
Net other comprehensive income		2			2
Balance as of December 31, 2013		(9	)		(9	)

Other comprehensive loss before
reclassifications		(5	)		(5	)
Amounts reclassified from accumulated other
comprehensive income		2			2
Net other comprehensive loss		(3	)		(3	)
Balance as of December 31, 2014		(12	)		(12	)

Other comprehensive income before
reclassifications		3			3
Amounts reclassified from accumulated other
comprehensive income		1			1
Net other comprehensive income		4			4
Balance as of December 31, 2015	$	(8	)	$	(8	)

(1)

All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SOUTHERN CALIFORNIA GAS COMPANY
(Dollars in millions)
				Pension			Total
				and other			accumulated other
	Financial			postretirement			comprehensive
	instruments			benefits			income (loss)
Balance as of December 31, 2012	$	(15	)	$	(3	)	$	(18	)

Other comprehensive loss before
reclassifications		―			(2	)		(2	)
Amounts reclassified from accumulated other
comprehensive income		1			1			2
Net other comprehensive income (loss)		1			(1	)		―
Balance as of December 31, 2013		(14	)		(4	)		(18	)

Other comprehensive loss before
reclassifications		―			(3	)		(3	)
Amounts reclassified from accumulated other
comprehensive income		―			3			3
Net other comprehensive income		―			―			―
Balance as of December 31, 2014		(14	)		(4	)		(18	)

Other comprehensive loss before
reclassifications		―			(1	)		(1	)
Net other comprehensive loss		―			(1	)		(1	)
Balance as of December 31, 2015	$	(14	)	$	(5	)	$	(19	)

(1)

All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated	Amounts reclassified from accumulated other									Affected line item
other comprehensive income (loss) components	comprehensive income (loss)									on Consolidated Statements of Operations
	Years ended December 31,
	2015			2014			2013
Sempra Energy Consolidated:
Foreign currency translation adjustments	$	―		$	―		$	270		Equity Earnings, Net of Income Tax(1)

Financial instruments:
Interest rate and foreign exchange instruments	$	18		$	21		$	11		Interest Expense
Interest rate instruments		―			(3	)		―		Gain on Sale of Equity Interests and Assets
Interest rate instruments		12			10			10		Equity Earnings, Before Income Tax
Interest rate instruments		13			―			―		Equity Earnings, Net of Income Tax
Commodity contracts not subject to rate recovery		(14	)		(8	)		(1	)	Revenues: Energy-Related Businesses
Total before income tax		29			20			20
		(4	)		(3	)		(4	)	Income Tax Expense
Net of income tax		25			17			16
		(15	)		(11	)		(9	)	Earnings Attributable to Noncontrolling Interests
	$	10		$	6		$	7

Pension and other postretirement benefits:
Net actuarial gain	$	―		$	―		$	3		See note (2) below
Amortization of actuarial loss		14			23			10		See note (2) below
Total before income tax		14			23			13
		(6	)		(9	)		(5	)	Income Tax Expense
Net of income tax	$	8		$	14		$	8

Total reclassifications for the period, net of tax	$	18		$	20		$	285
SDG&E:
Financial instruments:
Interest rate instruments	$	12		$	11		$	9		Interest Expense
		(12	)		(11	)		(9	)	Earnings Attributable to Noncontrolling Interest
	$	―		$	―		$	―

Pension and other postretirement benefits:
Net actuarial gain	$	―		$	―		$	2		See note (2) below
Amortization of actuarial loss		1			3			1		See note (2) below
Total before income tax		1			3			3
		―			(1	)		(1	)	Income Tax Expense
Net of income tax	$	1		$	2		$	2

Total reclassifications for the period, net of tax	$	1		$	2		$	2
SoCalGas:
Financial instruments:
Interest rate instruments	$	1		$	1		$	1		Interest Expense
		(1	)		(1	)		―		Income Tax Expense
Net of income tax	$	―		$	―		$	1

Pension and other postretirement benefits:
Amortization of actuarial loss	$	―		$	5		$	1		See note (2) below
Total before income tax		―			5			1
		―			(2	)		―		Income Tax Expense
Net of income tax	$	―		$	3		$	1

Total reclassifications for the period, net of tax	$	―		$	3		$	2

(1)

Represents cumulative foreign currency translation adjustment related to the impairment of our Argentine investments in 2006, which is substantially offset by an accrued liability established at that time. We provide additional information about these investments in Note 4.

(2)

Amounts are included in the computation of net periodic benefit cost (see "Net Periodic Benefit Cost" in Note 7).

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. Noncontrolling interests are reported as a separate component of equity on the Consolidated Balance Sheets. Earnings/losses attributable to the noncontrolling interests are separately identified on the Consolidated Statements of Operations, and net income/loss and comprehensive income/loss attributable to noncontrolling interests are separately identified on the Consolidated Statements of Comprehensive Income (Loss) and Consolidated Statements of Changes in Equity.

Sale of Noncontrolling Interests

In the first quarter of 2013, Sempra Energy’s subsidiary, IEnova, completed a private offering in the U.S. and outside of Mexico and a concurrent public offering in Mexico of common stock. The aggregate shares of common stock sold in the offerings represent approximately 18.9 percent of IEnova’s outstanding ownership interest. IEnova is reported within the Sempra Mexico reportable segment.

The proceeds from the offerings, net of offering costs, were approximately $574 million in U.S. dollar equivalent. IEnova has used the net proceeds of the offerings primarily for general corporate purposes, and for the funding of its investments and ongoing expansion plans. Consistent with applicable accounting guidance, changes in noncontrolling interests that do not result in a change of control are accounted for as equity transactions. When there are changes in noncontrolling interests of a subsidiary that do not result in a change of control, any difference between carrying value and fair value related to the change in ownership is recorded as an adjustment to shareholders’ equity. As a result of the offerings, we recorded an increase in Sempra Energy’s shareholders’ equity of $135 million in the first quarter of 2013 for the sale of IEnova shares to noncontrolling interests.

IEnova is a separate legal entity, formerly known as Sempra México, S.A. de C.V., comprised of Sempra Energy’s operations in Mexico. IEnova is included within our Sempra Mexico reportable segment, but is not the same in its entirety as the reportable segment. In addition to the IEnova operating companies, the Sempra Mexico segment includes, among other things, certain holding companies and risk management activity. Also, IEnova’s financial results are reported in Mexico under International Financial Reporting Standards (IFRS), as required by the Mexican Stock Exchange (La Bolsa Mexicana de Valores, S.A.B. de C.V., or BMV) where the shares are traded under the symbol IENOVA.

The private offering was exempt from registration under the U.S. Securities Act of 1933, as amended (the Securities Act), and shares in the private offering were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside of the United States, in accordance with Regulation S under the Securities Act. The shares were not registered under the Securities Act or any state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act and applicable securities laws.

Purchase of Noncontrolling Interests

In December 2014, we purchased 18,625,594 Luz del Sur shares for $74 million, increasing Sempra South American Utilities’ ownership from 79.8 percent to 83.6 percent.

Preferred Stock

The preferred stock at SoCalGas is presented at Sempra Energy as a noncontrolling interest at December 31, 2015 and 2014. SDG&E had contingently redeemable preferred stock outstanding at December 31, 2012 that was fully redeemed in October 2013, as we discuss in Note 11. At Sempra Energy, the preferred stock dividends of SDG&E and SoCalGas are charges against income related to noncontrolling interests. We provide additional information concerning preferred stock in Note 11.

Other Noncontrolling Interests

At December 31, 2015 and 2014, 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
(Dollars in millions)
	Percent ownership held by others
	December 31,						December 31,
	2015			2014			2015		2014
SDG&E:
Otay Mesa VIE		100	%		100	%	$	53	$	60
Sempra South American Utilities:
Chilquinta Energía subsidiaries(1)		23.5 - 43.4			23.6 - 43.4			21		23
Luz del Sur		16.4			16.4			164		177
Tecsur		9.8			9.8			4		4
Sempra Mexico:
IEnova, S.A.B. de C.V.		18.9			18.9			468		452
Sempra Natural Gas:
Bay Gas Storage Company, Ltd.		9.1			9.1			25		23
Liberty Gas Storage, LLC		23.2			25.0			14		14
Southern Gas Transmission Company		49.0			49.0			1		1
Total Sempra Energy							$	750	$	754

(1)

Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.

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. We record these revenues following the accrual method and recognize them upon delivery and performance. As described below, recorded revenues include those authorized by the CPUC to support our operations (“decoupled revenue”), as well as commodity costs that are passed through to core gas customers and electric customers:

Decoupled revenue – The regulatory framework permits the California Utilities to recover authorized revenue based on estimated annual demand forecasts approved in regular proceedings before the CPUC. Any difference between actual demand and the annual demand approved in the proceedings is recovered or refunded in authorized revenue in the subsequent year. This design, commonly known as “decoupling,” is intended to minimize any impact on earnings due to variability in volumetric demand for electricity and natural gas.

Commodity costs – The regulatory framework authorizes the California Utilities to recover the actual cost of natural gas procured and delivered to its core customers in rates substantially as incurred. Actual electricity procurement costs are recovered as power is delivered, or to the extent actual amounts vary from forecasts, generally recovered or refunded within the subsequent year. The California Utilities 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.

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 revenue recognition consistent with the California Utilities.

Our electric distribution utilities in South America, Chilquinta Energía and Luz del Sur, 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 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 rate-regulated accounting.

For Chilquinta Energía, rates for four-year periods related to distribution and sub-transmission are reviewed separately on an alternating basis every two years. Distribution rates for the period from November 2012 to October 2016 were published in April 2013, and tariff adjustments went into effect retroactively from November 2012. The next review process for distribution rates is scheduled to be completed in November 2016, covering the period from November 2016 to October 2020.

In April 2013, the CNE completed the process to establish Chilquinta Energía’s sub-transmission rates for the period from January 2011 to December 2014, with tariff adjustments going into effect retroactively from January 2011. The sub-transmission rates period has been extended for one year, for one time only, to December 2015 due to a change in law issued in December 2014. Accordingly, the next review process for sub-transmission rates is expected to be completed in the first half of 2016, with tariff adjustments going into effect retroactively from January 2016, covering the period from January 2016 to December 2019.

The components of tariffs above for Luz del Sur are reviewed and adjusted every four years. The final distribution rate-setting resolution for the 2013-2017 period was published in October 2013 and went into effect on November 1, 2013. The next rate review is scheduled to be completed in 2017, covering the period from November 2017 to October 2021.

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,
	2015			2014			2013
Electric revenues		$	5,158		$	5,209		$	4,911
Natural gas revenues			4,096			4,549			4,398
Total		$	9,254		$	9,758		$	9,309

(1)

Excludes intercompany revenues.

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 energy-services companies that provide electric construction services and recognizes these revenues when services are provided in accordance with contractual agreements. The energy-services company in Chile also generates revenue from selling electricity to non-regulated customers.

Sempra Mexico

Sempra Mexico’s Termoeléctrica de Mexicali natural gas-fired power plant generates revenues from selling electricity and/or capacity to the California Independent System Operator (ISO) and to governmental, public utility and wholesale power marketing entities. Sempra Mexico recognizes these revenues 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

For consolidated entities, Sempra Renewables generates revenues from the sale of solar power pursuant to power purchase agreements, and recognizes these revenues when the power is delivered. It also generates revenues for managing certain of its solar and wind project joint ventures.

Sempra Natural Gas

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 also records revenues from contractual counterparty obligations for non-delivery of LNG cargoes, as well as revenues from the sale of LNG and natural gas as deliveries are made to counterparties. 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. Prior to April 2015, Sempra Natural Gas generated revenues from selling electricity and/or capacity from its Mesquite Power facility (see Note 3) to the California ISO and to governmental, public utility and wholesale power marketing entities. Sempra Natural Gas recognized these revenues as the electricity was delivered and capacity was provided. Related to its LNG terminal, prior to October 1, 2014, the effective date of Cameron LNG JV, Sempra Natural Gas recognized revenues from reservation and usage fees. We discuss the deconsolidation of Cameron LNG, LLC and related assets further in Note 3.

OTHER COST OF SALES

Other Cost of Sales primarily includes

§	pipeline capacity costs, and pipeline transportation and natural gas marketing costs at Sempra Natural Gas;

§	electric construction services costs at Sempra South American Utilities’ energy-services companies; and

§	energy management service fees and costs associated with construction of a pipeline interconnect at Sempra Mexico.

OPERATION AND MAINTENANCE EXPENSES

Operation and Maintenance includes operating and maintenance costs, and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, litigation expense and rent.

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 Other Comprehensive Income (Loss) and in Accumulated Other Comprehensive Income (Loss).

Cash flows of these consolidated foreign subsidiaries are translated into U.S. dollars using average exchange rates for the period. We report the effect of exchange rate changes on cash balances held in foreign currencies in “Effect of Exchange Rate Changes on Cash and Cash Equivalents” on the Sempra Energy Consolidated Statements of Cash Flows.

Currency transaction losses in a currency other than the entity’s functional currency were $7 million, $15 million and $3 million for the years ended December 31, 2015, 2014 and 2013, respectively, and are included in Other Income, Net, on the Sempra Energy Consolidated Statements of Operations.

TRANSACTIONS WITH AFFILIATES

Amounts due from and to unconsolidated affiliates at Sempra Energy Consolidated, SDG&E and SoCalGas are as follows:

AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	December 31,
	2015			2014
Sempra Energy Consolidated:
Total due from various unconsolidated affiliates - current	$	6		$	38

Sempra South American Utilities(1):
Eletrans S.A.:
4% Note(2)	$	72		$	41
Sempra Mexico(1):
Affiliate of joint venture with Petróleos Mexicanos(3)
Note due November 13, 2017(4)(5)		3			44
Note due November 14, 2018(4)		42			40
Note due November 14, 2018(4)		34			33
Note due November 14, 2018(4)		8			8
Energía Sierra Juárez:
Note due June 15, 2018(6)		24			22
Sempra Natural Gas:
Cameron LNG JV		3			―
Total due from unconsolidated affiliates - noncurrent	$	186		$	188

Total due to various unconsolidated affiliates - current	$	(14	)	$	(2	)
SDG&E:
Total due from various unconsolidated affiliates - current	$	1		$	1

Sempra Energy	$	(34	)	$	(17	)
SoCalGas		(13	)		(4	)
Affiliate		(8	)		―
Total due to unconsolidated affiliates - current	$	(55	)	$	(21	)

Income taxes due from Sempra Energy(7)	$	28		$	16
SoCalGas:
Sempra Energy(8)	$	35		$	―
SDG&E		13			4
Total due from unconsolidated affiliates - current	$	48		$	4

Sempra Energy	$	―		$	(13	)
Total due to unconsolidated affiliate - current	$	―		$	(13	)

Income taxes due from Sempra Energy(7)	$	1		$	9

(1)	Amounts include principal balances plus accumulated interest outstanding.
(2)	U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans S.A., an affiliate of Chilquinta Energía.
(3)	Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company).
(4)	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 450 basis points (4.93 percent at December 31, 2015), to finance the Los Ramones Norte pipeline project.
(5)	In May 2015, $41 million was paid with proceeds from project financing at the affiliate.
(6)	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 637.5 basis points (6.80 percent at December 31, 2015), to finance the first phase of the Energía Sierra Juárez wind project.
(7)	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 each company having always filed a separate return.
(8)	Net receivable includes outstanding advances to Sempra Energy of $50 million at December 31, 2015 at an interest rate of 0.11 percent.

Revenues from unconsolidated affiliates are as follows:

REVENUES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Sempra Energy Consolidated		$	26		$	13		$	4
SDG&E			10			13			12
SoCalGas			75			69			70

Cost of sales from unconsolidated affiliates is as follows:

COST OF SALES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Sempra Energy Consolidated		$	107		$	78		$	78
SDG&E			49			17			19

California Utilities

Sempra Energy, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Also, from time-to-time, SDG&E and SoCalGas may make short-term advances of surplus cash to Sempra Energy at interest rates based on one-month commercial paper rates.

SoCalGas provides natural gas transportation and storage services for SDG&E and charges SDG&E for such services monthly. SoCalGas records revenues and SDG&E records a corresponding amount to cost of sales.

SDG&E and SoCalGas charge one another, as well as other Sempra Energy affiliates, for shared asset depreciation. SoCalGas and SDG&E record revenues and the affiliates record corresponding amounts to operation and maintenance expense.

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 revenues and costs related to SDG&E are not included in SoCalGas’ Consolidated Statements of Operations.

SDG&E has a 20-year contract for up to 155 MW of renewable power supplied from the Energía Sierra Juárez wind generation facility. Energía Sierra Juárez is a 50-percent owned and unconsolidated joint venture of Sempra Mexico that commenced operations in June 2015.

Sempra Renewables

Sempra Renewables, through its wholly owned subsidiary, Sempra Global Services, Inc. (SGS), provides project administration and operating and maintenance services to certain of its renewable energy unconsolidated joint ventures, including Auwahi Wind, Broken Bow 2 Wind, Copper Mountain Solar 2, Copper Mountain Solar 3 and Mesquite Solar 1. SGS also provides personnel to Mesquite Solar 1 on an employee leasing basis.

Sempra Renewables leases land and water rights to Mesquite Solar 1. The land lease agreement has a 30-year noncancelable lease term that expires in 2043. The water rights lease agreement terminates in 2042 but provides the option to renew the lease agreement for two additional 10-year terms.

Sempra Natural Gas

Sempra Natural Gas provides project administration and operating and maintenance services to Cameron LNG JV, as well as providing personnel on an employee leasing basis.

Sempra Natural Gas has an agreement with Rockies Express Pipeline LLC (Rockies Express) for capacity on the Rockies Express pipeline (REX) through November 2019. We discuss this agreement further in Note 15.

Guarantees

Sempra Energy has provided guarantees to certain of its solar and wind farm joint ventures and entered into completion guarantees related to the financing of the Cameron LNG JV project, as we discuss in Note 4.

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, 2015, Sempra Energy was in compliance with all covenants related to its debt agreements.

At December 31, 2015, 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 $7.6 billion. Additionally, the amount of restricted net assets of our unconsolidated entities is $3.8 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, $299 million of Sempra Energy’s consolidated retained earnings balance represents undistributed earnings of equity method investments at December 31, 2015.

California Utilities

The CPUC’s regulation of the California Utilities’ capital structures limits the amounts available for dividends and loans to Sempra Energy. At December 31, 2015, Sempra Energy could have received combined loans and dividends of approximately $600 million, funded by long-term debt issuance, from SDG&E and approximately $447 million from SoCalGas.

The payment and amount of future dividends by SDG&E and SoCalGas are at the discretion of their respective boards of directors. The following restrictions limit the amount of retained earnings that may be paid as common stock 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. The authorized percentage at December 31, 2015 is 52 percent at both SDG&E and 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 on these restrictions, at December 31, 2015, SDG&E’s restricted net assets were $4.6 billion and SoCalGas’ restricted net assets were $2.7 billion, which could not be transferred to Sempra Energy.

Sempra International

Significant restrictions of Sempra International subsidiaries include

§	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 $81 million at Sempra Energy’s consolidated Mexican subsidiaries at December 31, 2015.

Energía Sierra Juárez, a 50-percent owned and unconsolidated joint venture of Sempra Mexico (see Notes 3 and 4), has a long-term debt agreement that requires the establishment and funding of project and reserve accounts to which the proceeds of loans, letter of credit draws, project revenues and other amounts are deposited and applied in accordance with the debt agreement. The long-term debt agreement also limits the joint venture’s ability to incur liens, incur additional indebtedness, make acquisitions and undertake certain actions. Also, in connection with a debt agreement for the financing of Mexican value added tax, Energía Sierra Juárez had $10 million of restricted net assets at December 31, 2015.

§	Gasoductos de Chihuahua, Sempra Mexico’s joint venture with PEMEX (see Note 4), has a debt agreement that requires the joint venture to maintain a reserve account to pay the debt. Under these restrictions, net assets totaling $11 million are restricted at December 31, 2015.

Sempra U.S. Gas & Power

Significant restrictions of Sempra U.S. Gas & Power subsidiaries include

Wholly owned Copper Mountain Solar 1 has a long-term debt agreement that requires 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 agreement. This long-term debt agreement also limits Copper Mountain Solar 1’s ability to incur liens, incur additional indebtedness, make acquisitions and undertake certain actions, while also requiring maintenance of certain debt ratios. Under these restrictions, net assets totaling $9 million are restricted at December 31, 2015.

50-percent owned and unconsolidated joint ventures at Sempra Renewables have debt agreements that require each joint venture to maintain reserve accounts in order to pay the projects’ debt service and operation and maintenance requirements. We discuss Sempra Energy guarantees associated with these requirements in Note 4. At December 31, 2015, as a result of these requirements, there were total restricted net assets at these joint ventures of approximately $283 million.

§	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, 2015.

§	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, 2015.

Sempra Natural Gas has an equity method investment in Cameron LNG JV, which has 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. The debt agreements require the joint venture to maintain reserve accounts in order to pay the project debt service, and also contain restrictions related to the payment of dividends and other distributions to the members of the joint venture. We discuss Sempra Energy guarantees associated with Cameron LNG JV’s debt agreements in Note 4. Under these restrictions, net assets of Cameron LNG JV of approximately $3.5 billion are restricted at December 31, 2015.

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,
	2015			2014			2013
Sempra Energy Consolidated:
Allowance for equity funds used during construction	$	107		$	106		$	75
Investment gains(1)		3			27			39
Electrical infrastructure relocation income(2)		7			21			4
(Losses) gains on interest rate and foreign exchange instruments, net		(4	)		(15	)		17
Sale of other investments		11			2			―
Foreign currency transaction losses		(7	)		(15	)		(3	)
Regulatory interest, net(3)		3			6			5
Sundry, net		6			5			3
Total	$	126		$	137		$	140
SDG&E:
Allowance for equity funds used during construction	$	37		$	37		$	39
Regulatory interest, net(3)		3			6			4
Sundry, net		(4	)		(3	)		(3	)
Total	$	36		$	40		$	40
SoCalGas:
Allowance for equity funds used during construction	$	36		$	26		$	17
Regulatory interest, net(3)		―			―			1
Sundry, net		(6	)		(6	)		(7	)
Total	$	30		$	20		$	11

(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)	Income at Luz del Sur associated with the relocation of electrical infrastructure.
(3)	Interest on regulatory balancing accounts.

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) 2014-09, “Revenue from Contracts with Customers” (ASU 2014-09) and ASU 2015-14, “Revenue from Contracts with Customers: Deferral of the Effective Date” (ASU 2015-14): ASU 2014-09 provides accounting guidance for revenue from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers. The guidance also provides a model for the measurement and recognition of gains and losses on the sale of certain nonfinancial assets, such as property and equipment, including real estate. This guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach.

ASU 2015-14 defers the effective date of ASU 2014-09 by one year for all entities and permits early adoption on a limited basis. For public entities, ASU 2014-09 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted for fiscal years beginning after December 15, 2016, and is effective for interim periods in the year of adoption. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in which we will adopt the standard or our transition method.

ASU 2015-03, “Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) and ASU 2015-15, “Interest – Imputation of Interest: Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” (ASU 2015-15): ASU 2015-03 provides guidance on the financial statement presentation of debt issuance costs and requires an entity to present debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related long-term debt liability. This guidance must be applied using a full retrospective approach for all periods presented in the period of adoption.

We retrospectively adopted ASU 2015-03 during our annual reporting period ended December 31, 2015, and the adoption did not affect our results of operations or cash flows. The Sempra Energy, SDG&E and SoCalGas Consolidated Balance Sheets at December 31, 2014 reflect the reclassification of $81 million, $36 million, and $15 million, respectively, from Sundry to Long-Term Debt. We provide information about our long-term debt and related debt issuance costs in Note 5.

ASU 2015-15 clarifies ASU 2015-03 to provide additional guidance related to line-of-credit arrangements and states that the Securities and Exchange Commission staff would not object to an entity continuing to defer and present costs related to line-of-credit arrangements as an asset and subsequently amortizing the deferred costs ratably over the term of the line-of-credit arrangements, regardless of whether there are any outstanding borrowings on the line-of-credit arrangements. We adopted ASU 2015-15 for our annual reporting period ended December 31, 2015 and continue to include deferred costs related to our line-of-credit arrangements that are the subject of ASU 2015-15 in Sundry on the Sempra Energy, SDG&E and SoCalGas Consolidated Balance Sheets.

We adopted ASU 2015-17 on a prospective basis for our annual reporting period ended December 31, 2015, and the adoption did not affect our results of operations or cash flows. Prior Consolidated Balance Sheets of Sempra Energy, SDG&E and SoCalGas were not retrospectively adjusted. We discuss deferred tax assets and liabilities in Note 6.

ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01): ASU 2016-01 primarily affects the accounting for equity investments (except those accounted for under the equity method of accounting), financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, it clarifies guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. Upon adoption, entities must record a cumulative-effect adjustment to the balance sheet as of the beginning of the first reporting period in which the standard is adopted. The guidance on equity securities without readily determinable fair value will be applied prospectively to all equity investments that exist as of the date of adoption of the standard.

For public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2017. We will adopt ASU 2016-01 on January 1, 2018 as required and do not expect it to materially affect our financial condition, results of operations or cash flows. We will make the required changes to our disclosures upon adoption.

ASU 2016-02, “Leases” (ASU 2016-02): ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to not recognize leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting and ASU 2014-09. ASU 2016-02 also requires qualitative disclosures along with specific quantitative disclosures for both lessees and lessors.

NOTE 3. ACQUISITION AND DIVESTITURE ACTIVITY

We consolidate assets and liabilities acquired as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date.

POTENTIAL ACQUISITION

Sempra Mexico

IEnova and Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company) are 50-50 partners in the joint venture Gasoductos de Chihuahua (GdC). GdC develops and operates energy infrastructure in Mexico. On July 31, 2015, IEnova entered into an agreement to purchase PEMEX’s 50-percent interest for $1.325 billion (excluding the assumption of approximately $170 million of net debt), which upon closing would increase its interest from 50 percent to 100 percent. The assets involved in the acquisition included three natural gas pipelines, an ethane pipeline, and a liquid petroleum gas pipeline and associated storage terminal. The transaction excluded the Los Ramones Norte pipeline that is being developed under a separate joint venture with GdC, PEMEX, BlackRock and First Reserve, keeping IEnova’s interest in the project at the current 25 percent.

In December 2015, Mexico’s Comisión Federal de Competencia Económica (COFECE or Mexican Competition Commission) objected to the transaction as proposed and specified that, based upon previous antitrust rulings on PEMEX’s indirect ownership of the TDF S. de R.L. de C.V. liquid petroleum gas pipeline and the San Fernando natural gas pipeline, these assets must be offered by PEMEX in a competitive bidding process as a prerequisite for approval of any transaction involving these two assets. COFECE’s decision did not object to IEnova’s acquisition of the assets on a market concentration basis. The parties are in the process of restructuring the transaction so that PEMEX can proceed with a bidding process on these two assets in accordance with the COFECE ruling. IEnova will have the right to approve the winning bidder as a new partner. Any restructured transaction will require negotiation of satisfactory terms for the revised transaction, and will also be subject to IEnova and PEMEX board approvals and satisfactory completion of the Mexican antitrust review, and may require further approvals from Mexican authorities.

ACQUISITIONS

Sempra Renewables

In March 2015, Sempra Renewables invested $8 million to acquire a 100-percent interest in the Black Oak Getty Wind project, a 78-MW wind farm under development in Stearns County, Minnesota. The wind farm has a 20-year power purchase agreement with Minnesota Municipal Power Agency that will commence upon commercial operation in late 2016.

In May 2014, Sempra Renewables invested $121 million (as adjusted for financial position at closing) to become a 50-percent partner with Consolidated Edison Development (Con Edison Development) in four fully operating solar facilities in California. The joint venture includes Con Edison Development’s CED California Holdings, LLC portfolio, which consists of the 50-MW Alpaugh 50, the 20-MW Alpaugh North and the 20-MW White River 1 facilities in Tulare County, and the 20-MW Corcoran 1 facility in Kings County (collectively, the California solar partnership). The renewable power from all of the projects has been sold under long-term contracts. We account for our investment in the California solar partnership under the equity method.

DIVESTITURES

Sempra South American Utilities

In June 2013, Sempra South American Utilities completed the sale of its 43-percent interest in two Argentine natural gas utility holding companies, Sodigas Pampeana and Sodigas Sur, which we discuss in Note 4.

Sempra Renewables

In December 2015, Sempra Renewables sold its 100-percent interest in Rosamond Solar, a development project located in Antelope Valley, California for $26 million in cash. Upon completion of the sale that was comprised of $18 million of net property, plant and equipment, Sempra Renewables recognized a pretax gain of $8 million ($5 million after-tax), which is included in Gain on Sale of Equity Interests and Assets on our Consolidated Statement of Operations.

Sempra Natural Gas

In February 2013, Sempra Natural Gas sold one 625-MW block of its 1,250-MW Mesquite Power natural gas-fired power plant in Arizona, including a portion related to common plant, for approximately $371 million in cash. The asset was classified as held for sale at December 31, 2012. We recognized a pretax gain on the sale of $74 million ($44 million after-tax), included in Gain on Sale of Equity Interests and Assets on our Consolidated Statement of Operations in 2013.

In April 2015, Sempra Natural Gas sold the remaining 625-MW block of the Mesquite Power plant that was classified as held for sale at December 31, 2014, together with a related power sales contract, for net cash proceeds of $347 million. We recognized a pretax gain on the sale of $61 million ($36 million after-tax), included in Gain on Sale of Equity Interests and Assets on our Consolidated Statement of Operations in 2015.

SALE OF EQUITY INTERESTS AND JOINT VENTURE INVESTMENT

In 2014 and 2013, Sempra Energy completed the sale of equity interests in various subsidiaries that were previously wholly owned, as well as the contribution of Cameron LNG, LLC to a joint venture in exchange for an equity interest in the joint venture. The following table summarizes the deconsolidation of those subsidiaries, and we discuss each transaction below.

DECONSOLIDATION OF SUBSIDIARIES
(Dollars in millions)
	Years ended December 31,
	2014			2013
Proceeds, net of transaction costs(1)	$	152		$	169
Cash		(10	)		―
Restricted cash		(5	)		―
Other current assets		(23	)		―
Property, plant and equipment, net		(1,557	)		(727	)
Other assets		(65	)		(102	)
Accounts payable and accrued expenses		188			―
Due to affiliate		39			―
Long-term debt, including current portion		251			443
Other liabilities		12			50
Accumulated other comprehensive income		(7	)		―
Gain on sale of equity interests(2)		(60	)		(40	)
(Increase) in equity method investments upon
deconsolidation	$	(1,085	)	$	(207	)

(1)	Transaction costs were negligible in 2014 and $6 million in 2013.
(2)	Included in Gain on Sale of Equity Interests and Assets on our Consolidated Statements of Operations.

Sempra Mexico

In July 2014, Sempra Mexico completed the sale of a 50-percent interest in the 155-MW first phase of its Energía Sierra Juárez wind project to a wholly owned subsidiary of InterGen N.V. for cash proceeds of $24 million, net of $2 million cash sold. Sempra Mexico recognized a pretax gain on the sale of $19 million ($14 million after-tax). Included in the deconsolidation were net property, plant and equipment of $137 million and long-term debt, including current portion, of $82 million. The gain on sale included a $7 million after-tax gain attributable to the remeasurement of the retained investment to fair value. Our remaining 50-percent interest in Energía Sierra Juárez is accounted for under the equity method.

Sempra Renewables

In November 2014, Sempra Renewables formed a joint venture with Con Edison Development, by selling a 50-percent interest in the 75-MW Broken Bow 2 Wind project for $58 million in cash. Included in the deconsolidation were net property, plant and equipment of $151 million and long-term debt, including current portion, of $72 million. Sempra Renewables recognized a pretax gain on the sale of $14 million ($8 million after-tax).

In March 2014, Sempra Renewables formed a joint venture with Con Edison Development, by selling a 50-percent interest in its 250-MW Copper Mountain Solar 3 solar power facility for $66 million in cash, net of $2 million cash sold. Included in the deconsolidation were net property, plant and equipment of $247 million and long-term debt, including current portion, of $97 million. Sempra Renewables recognized a pretax gain on the sale of $27 million ($16 million after-tax).

In September 2013, Sempra Renewables formed a joint venture with Con Edison Development, by selling a 50-percent interest in its 150-MW Mesquite Solar 1 solar power facility for $103 million in cash. Included in the deconsolidation were net property, plant and equipment of $461 million and long-term debt, including current portion, of $297 million. Sempra Renewables recognized a pretax gain on the sale of $36 million ($22 million after-tax).

In July 2013, Sempra Renewables formed a joint venture with Con Edison Development, by selling a 50-percent interest in its 150-MW Copper Mountain Solar 2 solar power facility for $72 million in cash. Included in the deconsolidation were net property, plant and equipment of $266 million and long-term debt, including current portion, of $146 million. Sempra Renewables recognized a pretax gain on the sale of $4 million ($2 million after-tax).

Our remaining 50-percent interests in these investments are accounted for under the equity method. Based on the nature of the underlying assets, these investments are considered in-substance real estate. Therefore, in accordance with applicable U.S. GAAP, for each of these investment transactions, the equity method investments were measured at their historical cost and no portion of the gains was attributable to a remeasurement of the retained investments to fair value. Pretax gains from the sale of our interests in these investments are included in Gain on Sale of Equity Interests and Assets on our Consolidated Statements of Operations.

Sempra Natural Gas

On August 6, 2014, Sempra Natural Gas and its project partners, comprised of affiliates of ENGIE S.A. (formerly GDF SUEZ S.A.), Mitsui & Co., Ltd., and Mitsubishi Corporation (through a related company jointly established with Nippon Yusen Kabushiki Kaisha), provided their respective final investment decision with regard to the investment in the development, construction and operation of the natural gas liquefaction export facility at the terminal in Hackberry, Louisiana, owned by Cameron LNG, LLC. The Cameron LNG liquefaction project utilizes Cameron LNG, LLC’s existing facilities, including two marine berths, three LNG storage tanks, and vaporization capability of 1.5 billion cubic feet (Bcf) per day. The current liquefaction project is comprised of three liquefaction trains and is being designed to a nameplate capacity of 13.9 million tonnes per annum (Mtpa) of LNG, with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. Commercial operation of all three trains is expected to commence in 2018, with the first year of full operations in 2019. The effective date of Cameron LNG JV among Sempra Energy and its project partners occurred on October 1, 2014 after satisfaction of various conditions, including receipt of final regulatory approval and satisfaction of conditions precedent to the first disbursement of the project financing.

Our equity in Cameron LNG JV was derived from our contribution of Cameron LNG, LLC to the joint venture at its historical carrying value. Included in the deconsolidation was net property, plant and equipment of approximately $1.0 billion. The other partners were issued equity interests in Cameron LNG JV in an aggregate of 49.8 percent. Cameron LNG, LLC thereby ceased to be wholly owned by Sempra Natural Gas, which retained a 50.2 percent interest in Cameron LNG JV. As of the October 1, 2014 effective date, Sempra Natural Gas began to account for its investment in Cameron LNG JV under the equity method. Sempra Energy did not recognize a gain or loss related to the contribution of Cameron LNG, LLC.

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

We generally account for investments under the equity method when we have significant influence over, but do not have control of, these entities. In these cases, our pro rata shares of the entities’ net assets are included in Investments on the Consolidated Balance Sheets. We adjust each investment for our share of each investee’s earnings or losses, dividends, and other comprehensive income or loss. We evaluate the carrying value of unconsolidated entities for impairment under the U.S. GAAP provisions for equity method investments.

We provide the carrying value of our investments and earnings (losses) on these investments below:

EQUITY METHOD AND OTHER INVESTMENT BALANCES
(Dollars in millions)
	December 31,
	2015			2014
Sempra South American Utilities:
Eletrans(1)	$	(12	)	$	(8	)
Sempra Mexico:
Energía Sierra Juárez(2)		30			25
Gasoductos de Chihuahua(3)		489			409
Sempra Renewables:
Wind:
Auwahi Wind		44			45
Broken Bow 2 Wind		41			44
Cedar Creek 2 Wind		75			82
Flat Ridge 2 Wind		275			284
Fowler Ridge 2 Wind		46			46
Mehoopany Wind		92			82
Solar:
California solar partnership		120			125
Copper Mountain Solar 2		32			61
Copper Mountain Solar 3		44			56
Mesquite Solar 1		86			86
Sempra Natural Gas:
Cameron LNG JV(4)		983			1,007
Rockies Express Pipeline LLC(5)		477			340
Parent and other:
RBS Sempra Commodities LLP		67			71
Total equity method investments		2,889			2,755
Other(6)		16			93
Total	$	2,905		$	2,848

(1)	Includes losses on forward exchange contracts, which we discuss below.
(2)	The carrying value of our equity method investment is $12 million higher than the underlying equity in the net assets of the investee at December 31, 2015 and 2014 due to the remeasurement of our retained investment to fair value.
(3)	The carrying value of our equity method investment is $65 million higher than the underlying equity in the net assets of the investee at December 31, 2015 and 2014 due to equity method goodwill.
(4)	The carrying value of our equity method investment is $143 million and $94 million higher than the underlying equity in the net assets of the investee at December 31, 2015 and 2014, respectively, primarily due to guarantees, which we discuss below, and interest capitalized on the investment, as the joint venture has not commenced its planned principal operations.
(5)	The carrying value of our equity method investment is $357 million and $369 million lower than the underlying equity in the net assets of the investee at December 31, 2015 and 2014, respectively, due to an impairment charge recorded in 2012.
(6)	Other includes Sempra Natural Gas’ $77 million investment in industrial development bonds at Mississippi Hub at December 31, 2014, which increased by $2 million and was fully redeemed in June 2015.

EARNINGS (LOSSES) FROM EQUITY METHOD INVESTMENTS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Earnings (losses) recorded before income tax:
Sempra Renewables:
Wind:
Auwahi Wind	$	4		$	4		$	4
Broken Bow 2 Wind		(2	)		―			―
Cedar Creek 2 Wind		(6	)		(3	)		(4	)
Flat Ridge 2 Wind		(12	)		(7	)		(8	)
Fowler Ridge 2 Wind		4			2			(3	)
Mehoopany Wind		(1	)		(1	)		(2	)
Solar:
California solar partnership		6			6			―
Copper Mountain Solar 2		7			3			―
Copper Mountain Solar 3		8			2			―
Mesquite Solar 1		16			14			1
Sempra Natural Gas:
Cameron LNG JV		5			2			―
Rockies Express Pipeline LLC		79			60			47
Parent and other:
RBS Sempra Commodities LLP		(4	)		(2	)		(3	)
Other		―			1			(1	)
	$	104		$	81		$	31

Earnings (losses) recorded net of income tax(1):
Sempra South American Utilities:
Sodigas Pampeana and Sodigas Sur	$	―		$	―		$	(11	)
Eletrans		(4	)		(4	)		(4	)
Sempra Mexico:
Energía Sierra Juárez		6			3			―
Gasoductos de Chihuahua		83			39			39
	$	85		$	38		$	24

(1)

As the earnings (losses) from these investments are recorded net of income tax, they are presented below the income tax expense line, so as not to impact our effective income tax rate.

Our share of the undistributed earnings of equity method investments was $299 million and $187 million at December 31, 2015 and 2014, respectively. The December 31, 2015 and 2014 balances do not include remaining distributions of $67 million and $71 million, respectively, associated with our investment in RBS Sempra Commodities LLP (RBS Sempra Commodities) and expected to be received from the partnership as it is dissolved, as we discuss below.

SEMPRA SOUTH AMERICAN UTILITIES

Sempra South American Utilities previously owned 43 percent of two Argentine natural gas utility holding companies, Sodigas Pampeana and Sodigas Sur. In December 2006, we decided to sell these investments and actively pursued their sale since that time. In the first quarter of 2013, we recorded a noncash impairment charge of $10 million ($7 million after-tax) to reduce the carrying value of our investments to estimated fair value at that time. The net charge is reported in Equity Earnings, Net of Income Tax, on the Consolidated Statement of Operations for the year ended December 31, 2013. In June 2013, we completed the sale of our Argentine investments for $13 million in cash and recorded an additional $7 million loss ($4 million after-tax) on the sale, which is also included in Equity Earnings, Net of Income Tax.

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 had reduced the carrying value of its investments by a cumulative total of $270 million prior to the sale. 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). As a result of the sale of our investments, this cumulative foreign currency translation adjustment was reclassified to Equity Earnings, Net of Income Tax, where it was substantially offset by the elimination of a $250 million accrued liability established in 2006.

In 2013, Chilquinta Energía entered into two 50-percent owned joint ventures, Eletrans S.A. and Eletrans II S.A. (collectively, Eletrans), with Sociedad Austral de Electricidad Sociedad Anónima (SAESA) to construct four transmission lines in Chile. In 2013, Eletrans entered into forward exchange contracts to manage the foreign currency exchange rate risk of the Chilean Unidad de Fomento (CLF) relative to the U.S. dollar, related to certain construction commitments that are denominated in CLF. The forward exchange contracts settle based on anticipated payments to vendors, generally monthly, ending in July 2018. During each of the years ended December 31, 2015, 2014 and 2013, we recorded $4 million of equity losses related to these forward contracts in Equity Earnings, Net of Income Tax, on the Consolidated Statements of Operations.

SEMPRA MEXICO

Sempra Mexico owns a 50-percent interest in GdC, a joint venture with PEMEX. The joint venture operates several natural gas pipelines and propane and ethane systems in Mexico and is developing natural gas pipelines and other energy infrastructure. See Note 3 for discussion regarding Sempra Mexico’s potential acquisition of the remaining 50-percent interest in GdC.

SEMPRA RENEWABLES

Sempra Renewables has 50-percent interests in wind and solar energy generation facilities in operation or under construction in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Nebraska, Nevada, and Pennsylvania. The generating capacities of the facilities in operation or under construction are contracted under long-term power purchase agreements. These facilities are accounted for under the equity method.

SEMPRA NATURAL GAS

Rockies Express

Sempra Natural Gas owns a 25-percent interest in Rockies Express, a partnership that operates a natural gas pipeline, REX, that links the Rocky Mountain region to the upper Midwest and the eastern United States. Tallgrass Energy Partners, L.P. (Tallgrass) owns a 50-percent interest and Phillips 66 owns the remaining 25-percent interest. Our investment in Rockies Express is accounted for as an equity method investment.

In April 2015, Sempra Natural Gas invested $113 million of cash in Rockies Express to repay project debt that matured in early 2015.

Cameron LNG JV

October 1, 2014 was the effective date of the formation of a joint venture partnership among Sempra Energy and three project partners involving Sempra Natural Gas’ Cameron LNG facility in Louisiana, as we discuss in Note 3. As of October 1, 2014, Sempra Natural Gas began accounting for its investment in Cameron LNG JV under the equity method.

During the year ended December 31, 2015, Sempra Natural Gas invested $10 million of cash in Cameron LNG JV and capitalized $49 million of interest related to this equity method investment that has not commenced planned principal operations.

Cameron LNG JV Financing

General. On August 6, 2014, Cameron LNG JV entered into finance documents (collectively, Loan Facility Agreements) for senior secured financing in an initial aggregate principal amount of up to $7.4 billion under three debt facilities provided by the Japan Bank for International Cooperation (JBIC) and 29 international commercial banks, some of which will benefit from insurance coverage provided by Nippon Export and Investment Insurance (NEXI).

The Cameron LNG JV Loan Facility Agreements and related finance documents provide senior secured term loans with a maturity date of July 15, 2030. The proceeds of the loans will be used for financing the cost of development and construction of the three-train Cameron LNG project. The Loan Facility Agreements and related finance documents contain customary representations and affirmative and negative covenants for project finance facilities of this kind with the lenders of the type participating in the Cameron LNG JV financing.

On August 6, 2014, Sempra Energy entered into a completion agreement in favor of HSBC Bank USA, National Association, as security trustee for the benefit of all of Cameron LNG JV’s creditors under the Loan Facility Agreements. Pursuant to this completion agreement, Sempra Energy has severally guaranteed 50.2 percent of Cameron LNG JV’s senior debt obligations under the Loan Facility Agreements, or a maximum principal amount of $3.7 billion. Completion guarantees for the remaining 49.8 percent of Cameron LNG JV’s senior secured financing have been provided by the other project partners. The occurrence of the effectiveness of the Cameron LNG Holdings joint venture on October 1, 2014, as further described in Note 3, was a condition precedent to first disbursement of funds under the Loan Facility Agreements. The Sempra Energy completion guarantee of 50.2 percent of Cameron LNG JV financing also became effective upon effectiveness of the Cameron LNG Holdings joint venture. Sempra Energy’s completion agreement and guarantee will terminate upon financial completion of the three-train Cameron LNG project, which is subject to satisfaction of certain conditions, including all three trains achieving commercial operations and meeting certain operational performance tests. Financial completion is scheduled for the second half of 2019. Sempra Energy recorded a liability of $82 million on October 1, 2014 for the fair value of its obligations associated with the Loan Facility Agreements, which constitute guarantees. This liability is being reduced on a straight-line basis over the duration of the guarantees by recognizing equity earnings from Cameron LNG JV, included in Equity Earnings, Before Income Tax.

On August 6, 2014, Sempra Energy and the other project partners entered into a transfer restrictions agreement with Société Générale, as intercreditor agent for the lenders under the Loan Facility Agreements. Pursuant to the transfer restriction agreement, Sempra Energy agreed to certain restrictions on its ability to dispose of Sempra Energy’s indirect fully diluted economic and beneficial ownership interests in Cameron LNG JV. These restrictions vary over time. Prior to financial completion of the three-train Cameron LNG project, Sempra Energy must retain 37.65 percent of such interest in Cameron LNG JV. Starting six months after financial completion of the three-train Cameron LNG project, Sempra Energy must retain at least 10 percent of the indirect fully diluted economic and beneficial ownership interest in Cameron LNG JV. In addition, at all times, a Sempra Energy controlled (but not necessarily wholly owned) subsidiary must directly own 50.2 percent of the membership interests of the Cameron LNG JV.

Interest. The weighted average all-in cost of the loans outstanding under all the Loan Facility Agreements (and based on certain assumptions as to timing of drawdown) is 1.59 percent per annum over LIBOR prior to financial completion of the project and 1.78 percent per annum over LIBOR following financial completion of the project. The Loan Facility Agreements require Cameron LNG JV to hedge 50 percent of outstanding borrowings to fix the interest rate, beginning in 2016. The hedges are to remain in place until the debt principal has been amortized by 50 percent. In November 2014, Cameron LNG JV entered into floating-to-fixed interest rate swaps for approximately $3.7 billion notional amount, resulting in an effective fixed rate of 3.19 percent. In June 2015, Cameron LNG JV entered into additional floating-to-fixed interest rate swaps for approximately $1.5 billion notional amount, resulting in an effective fixed rate of 3.32 percent.

Mandatory Prepayments. Cameron LNG JV must make mandatory prepayments of all loans made under the Loan Facility Agreements under certain circumstances, including: upon receipt of certain insurance proceeds and expropriation compensation; upon receipt of certain performance liquidated damages under Cameron LNG JV’s engineering, procurement and construction contract for the liquefaction terminal; in connection with the loss of its tolling agreements or export permits that result in a reduction of Cameron LNG JV’s debt service coverage ratios below a specified threshold; if it becomes unlawful in any applicable jurisdiction for a lender to fund or maintain its loans; or in connection with any mandatory prepayment of senior notes outstanding (if any).

The loans under the NEXI Covered Loan Facility Agreement and the loans held by JBIC under the JBIC Loan Facility Agreement are subject to certain additional mandatory prepayments that would be triggered if the Japanese sponsors fail to maintain certain ownership interests in Cameron LNG JV, if Cameron LNG JV’s Japanese tolling customers do not hold commitments for a certain quantum of nameplate capacity at the liquefaction terminal or if the aggregate annual contracted LNG commitments by Cameron LNG JV’s tolling customers to Japanese LNG buyers fall below a certain minimum threshold under certain circumstances.

Events of Default. Cameron LNG JV’s Loan Facility Agreements and related finance documents also contain events of default customary for such financings, including events of default for: failure to pay principal and interest on the due date; insolvency of Cameron LNG JV; abandonment of the project; expropriation; unenforceability or termination of the finance documents; and a failure to achieve financial completion of the project by a financial completion deadline date of September 30, 2021 (with up to additional 365 days extension beyond such date permitted in cases of force majeure). A delay in construction that results in a failure to achieve financial completion of the project by this financial completion deadline date would therefore result in an event of default under Cameron LNG JV’s financing and a potential demand on Sempra Energy’s guarantees.

Security. To support Cameron LNG JV’s obligations under the Loan Facility Agreements and related finance documents, Cameron LNG JV has granted security over all of its assets, subject to customary exceptions, and all equity interests in Cameron LNG JV have been pledged to HSBC Bank USA, National Association, as security trustee for the benefit of all Cameron LNG JV’s creditors. As a result, an enforcement action by the lenders taken in accordance with the finance documents could result in the exercise of such security interests by the lenders and the loss of ownership interests in Cameron LNG JV by Sempra Energy and the other project partners.

The security trustee under Cameron LNG JV’s financing can demand that a payment be made by Sempra Energy under its guarantees of Sempra Energy’s 50.2 percent share of senior debt obligations due and payable either on the date such amounts were due from Cameron LNG JV (taking into account cure periods) in the event of a failure by Cameron LNG JV to pay such senior debt obligations when they become due or within 10 business days in the event of an acceleration of senior debt obligations under the terms of the finance documents. If an event of default occurs under the Sempra Energy completion agreement, the security trustee can demand that Sempra Energy purchase its 50.2 percent share of all then outstanding senior debt obligations within five business days (other than in the case of a bankruptcy default, which is automatic).

RBS SEMPRA COMMODITIES

RBS Sempra Commodities is a United Kingdom limited liability partnership formed by Sempra Energy and The Royal Bank of Scotland plc (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 2010 and 2011. We account for our investment in RBS Sempra Commodities under the equity method, and report miscellaneous costs since the sale of the business in Parent and Other.

We recorded $4 million, $2 million and $3 million in pretax equity losses for the years ended December 31, 2015, 2014 and 2013, respectively.

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 $50 million in 2013. The investment balance of $67 million at December 31, 2015 reflects remaining distributions expected to be received from the partnership in accordance with the Letter Agreement. The timing and amount of distributions, if any, may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 15 under “Legal Proceedings – 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.

SUMMARIZED FINANCIAL INFORMATION

We present summarized financial information below, aggregated for all of our equity method investments for the periods in which we were invested in the entity. The amounts below represent the aggregate financial position and results of operations of 100 percent of each of Sempra Energy’s equity method investments.

SUMMARIZED FINANCIAL INFORMATION
(Dollars in millions)
	Years ended December 31,
	2015				2014				2013
Gross revenues		$	1,533			$	1,296			$	1,734
Operating expense			(845	)			(749	)			(1,287	)
Income from operations			688				547				447
Interest expense			(312	)			(298	)			(251	)
Net income/Earnings(1)			440				291				222

	At December 31,
	2015			2014
Current assets		$	750		$	865
Noncurrent assets			15,112			13,161
Current liabilities			859			1,131
Noncurrent liabilities			7,862			6,228

(1)

Except for Gasoductos de Chihuahua, Energía Sierra Juárez, Eletrans and the Argentine investments, there was no income tax recorded by the entities, as they are primarily domestic partnerships.

GUARANTEES

Project financing at our solar and wind joint ventures, except Auwahi Wind, requires the joint venture partners, for each partner’s interest, 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, operation and maintenance, and firm transmission and production tax credits reserve accounts are not maintained at specific thresholds. In some cases, the joint venture partners have provided guarantees to the lenders in lieu of the projects funding the reserve account requirements. We recorded liabilities for the fair value of certain of our obligations associated with these guarantees and the liabilities are being amortized over their expected lives. The outstanding loans at our solar and wind joint ventures are not guaranteed by the partners, but are secured by project assets.

At December 31, 2015, we provided guarantees aggregating a maximum of $332 million with an associated aggregated carrying value of $10 million for guarantees related to project financing. In addition, at December 31, 2015, we provided guarantees to solar and wind farm joint ventures aggregating a maximum of $170 million with an associated aggregated carrying value of $2 million, primarily related to purchased-power agreements and engineering, procurement and construction contracts.

NOTE 5. DEBT AND CREDIT FACILITIES

LINES OF CREDIT

At December 31, 2015, Sempra Energy Consolidated had an aggregate of $4.2 billion in three primary committed lines of credit for Sempra Energy, Sempra Global and the California Utilities to provide liquidity and to support commercial paper, the major components of which we detail below. Available unused credit on these lines at December 31, 2015 was $3.7 billion. Our foreign operations have additional general purpose credit facilities, aggregating $1.1 billion at December 31, 2015. Available unused credit on these lines totaled $889 million at December 31, 2015.

Sempra Energy

Sempra Energy has a $1 billion, five-year syndicated revolving credit agreement, as amended and restated in October 2015, expiring in October 2020. Citibank, N.A. serves as administrative agent for the syndicate of 20 lenders, and no single lender has greater than a 7-percent share. The amended credit facility restates and supersedes Sempra Energy’s $1.067 billion credit agreement that was to expire in 2017.

Borrowings bear interest at benchmark rates plus a margin that varies with 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, 2015, Sempra Energy was in compliance with this and all other financial covenants under the credit facility. The facility also provides for issuance of up to $400 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, 2015, Sempra Energy had no outstanding borrowings or letters of credit supported by the facility.

Sempra Global

Sempra Global has a $2.21 billion, five-year syndicated revolving credit agreement, as amended and restated in October 2015, expiring in October 2020. Citibank, N.A. serves as administrative agent for the syndicate of 20 lenders, and no single lender has greater than a 7-percent share. The amended credit facility restates and supersedes Sempra Global’s $2.189 billion credit agreement that was to expire in 2017.

Sempra Energy guarantees Sempra Global’s obligations under the credit facility. Borrowings bear interest at benchmark rates plus a margin that varies with 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, 2015, Sempra Energy was in compliance with this and all other financial covenants under the credit facility.

At December 31, 2015, Sempra Global had $335 million of commercial paper outstanding supported by the facility and $1.87 billion of available unused credit on the line.

California Utilities

SDG&E and SoCalGas have a combined $1 billion, five-year syndicated revolving credit agreement, as amended and restated in October 2015, expiring in October 2020. JPMorgan Chase Bank, N.A. serves as administrative agent for the syndicate of 20 lenders, and no single lender has greater than a 7-percent share. The agreement permits each utility to individually borrow up to $750 million, subject to a combined limit of $1 billion 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 $250 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. The amended credit facility restates and supersedes the California Utilities’ $877 million credit agreement that was to expire in 2017.

Borrowings bear interest at benchmark rates plus a margin that varies with the borrowing utility’s credit rating. 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. At December 31, 2015, the California Utilities were in compliance with this and all other financial covenants under the credit facility.

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, 2015, SDG&E had $168 million of commercial paper outstanding, supported by the facility. SoCalGas had no outstanding borrowings supported by the facility. Available unused credit on the line at December 31, 2015 was $582 million and $750 million at SDG&E and SoCalGas, respectively, subject to the $1 billion maximum combined credit limit.

Sempra South American Utilities

Sempra South American Utilities has Peruvian Nuevo Sol and Chilean Peso-denominated credit facilities aggregating $544 million U.S. dollar equivalent, expiring between 2016 and 2018. The credit facilities were entered into to finance working capital and for general corporate purposes. The Peruvian facilities require a debt to equity ratio of no more than 170 percent. At December 31, 2015, Peru was in compliance with this financial covenant under the credit facilities. At December 31, 2015, Sempra South American Utilities had outstanding borrowings of $154 million and bank guarantees of $10 million against the Peruvian facilities, and $270 million of available unused credit. There were no outstanding borrowings at December 31, 2015 under the $110 million Chilean facility.

Sempra Mexico

In 2014, IEnova entered into an agreement for a $200 million, U.S. dollar-denominated, three-year corporate revolving credit facility with Banco Santander, (México), S.A., Institución de Banca Múltiple, Grupo Financiero Santander Mexico. Also in 2014, IEnova entered into an agreement for a $100 million, U.S. dollar-denominated, three-year corporate revolving credit facility with Sumitomo Mitsui Banking Corporation. Both revolving credit facilities were entered into to finance working capital and for general corporate purposes.

In August 2015, IEnova entered into a $400 million, five-year revolving credit agreement to replace, and repay the $210 million in outstanding borrowings under, the two revolving credit facilities described above. The lenders are Banco Santander (México), S.A., Institución de Banca Múltiple, Grupo Financiero Santander México, The Bank of Tokyo - Mitsubishi UFJ, LTD., The Bank of Nova Scotia and Sumitomo Mitsui Banking Corporation. In December 2015, an amendment to the agreement increased the amount of credit on the line from $400 million to $600 million. At December 31, 2015, IEnova had $91 million of outstanding borrowings supported by the facility, and available unused credit on the line was $509 million.

WEIGHTED AVERAGE INTEREST RATES

The weighted average interest rates on the total short-term debt outstanding at Sempra Energy Consolidated were 1.09 percent and 0.70 percent at December 31, 2015 and 2014, respectively. The weighted average interest rate on the total short-term debt at SDG&E was 1.01 percent at December 31, 2015. At December 31, 2014, the weighted average interest rates on total short-term debt at SDG&E and SoCalGas were 0.27 percent and 0.25 percent, respectively.

LONG-TERM DEBT

The following tables show the detail and maturities of long-term debt outstanding:

LONG-TERM DEBT
(Dollars in millions)
	December 31,
	2015			2014(1)
SDG&E
First mortgage bonds (secured by plant assets):
5.3% November 15, 2015	$	―		$	250
Bonds at variable rates (0.68% at December 31, 2015) March 9, 2017		140			―
1.65% July 1, 2018(2)		161			161
3% August 15, 2021		350			350
1.914% payable 2015 through February 2022		232			―
3.6% September 1, 2023		450			450
6% June 1, 2026		250			250
5% to 5.25% payable 2015 through December 2027(2)		105			150
5.875% January and February 2034(2)		176			176
5.35% May 15, 2035		250			250
6.125% September 15, 2037		250			250
4% May 1, 2039(2)		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			250
		3,989			3,912
Other long-term debt (unsecured unless otherwise noted):
5.3% Notes July 1, 2021(2)(3)		―			39
5.5% Notes December 1, 2021(2)(3)		―			60
4.9% Notes March 1, 2023(2)(3)		―			25
5.2925% OMEC LLC loan
payable 2013 through April 2019 (secured by OMEC plant assets)		315			325
366-day commercial paper borrowings May 2015, classified as long-term debt
(0.40% weighted average at December 31, 2014)		―			100
Capital lease obligations:
Purchased-power agreements		243			233
Other		1			1
		559			783
		4,548			4,695
Current portion of long-term debt		(50	)		(365	)
Unamortized discount on long-term debt		(10	)		(11	)
Unamortized long-term debt issuance costs		(33	)		(36	)
Total SDG&E		4,455			4,283

SoCalGas
First mortgage bonds (secured by plant assets):
5.45% April 15, 2018		250			250
1.55% June 15, 2018		250			―
3.15% September 15, 2024		500			500
3.2% June 15, 2025		350			―
5.75% November 15, 2035		250			250
5.125% November 15, 2040		300			300
3.75% September 15, 2042		350			350
4.45% March 15, 2044		250			250
		2,500			1,900
Other long-term debt (unsecured):
4.75% Notes May 14, 2016(2)		8			8
5.67% Notes January 18, 2028		5			5
Capital lease obligations		1			1
		14			14
		2,514			1,914
Current portion of long-term debt		(9	)		―
Unamortized discount on long-term debt		(7	)		(8	)
Unamortized long-term debt issuance costs		(17	)		(15	)
Total SoCalGas		2,481			1,891

LONG-TERM DEBT (CONTINUED)
(Dollars in millions)
		December 31,
		2015			2014(1)
Sempra Energy
Other long-term debt (unsecured):
	6.5% Notes June 1, 2016, including $300 at variable rates after fixed-to-floating
	rate swaps effective January 2011 (4.77% at December 31, 2015)	$	750		$	750
	2.3% Notes April 1, 2017		600			600
	6.15% Notes June 15, 2018		500			500
	9.8% Notes February 15, 2019		500			500
	2.4% Notes March 15, 2020		500			―
	2.85% Notes November 15, 2020		400			―
	2.875% Notes October 1, 2022		500			500
	4.05% Notes December 1, 2023		500			500
	3.55% Notes June 15, 2024		500			500
	3.75% Notes November 15, 2025		350			―
	6% Notes October 15, 2039		750			750
Market value adjustments for interest rate swaps, net			(2	)		―
Build-to-suit lease(4)			136			75
Sempra South American Utilities
Other long-term debt (unsecured):
Chilquinta Energía
	4.25% Series B Bonds payable 2014 through October 30, 2030(2)		170			192
Luz del Sur
	Bank loans 5.05% to 6.7% payable 2016 through December 2018		136			91
	Notes at 4.75% to 8.75% payable 2014 through September 2029		292			345
	Other bonds at 3.77% to 4.61% payable 2020 through May 2022		8			10
	Capital lease		6			―
Sempra Mexico
Other long-term debt (unsecured):
	Notes February 8, 2018 at variable rates (2.66% after floating-to-fixed rate cross-currency
	swaps effective February 2013)		75			88
	6.3% Notes February 2, 2023 (4.12% after cross-currency swap)		227			265
	Notes at variable rates (1.28% at December 31, 2014) August 25, 2017(2)(3)		―			51
Sempra Renewables
Other long-term debt (secured by project assets):
	Loan at variable rates (2.24% at December 31, 2015) payable 2012 through December 2028,
	except for $69 at 4.54% after floating-to-fixed rate swaps effective June 2012(2)		91			97
Sempra Natural Gas
First mortgage bonds (Mobile Gas, secured by plant assets):
	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% October 1, 2016(2)		19			19
	8.45% Notes payable 2012 through December 2017, secured by parent guarantee		11			16
	3.1% Notes December 30, 2018, secured by plant assets(2)		5			5
	4.5% Industrial development bonds July 1, 2024, secured by a promissory note(2)(3)		―			77
	Industrial development bonds at variable rates (0.05% at December 31, 2014)
	August 1, 2037, secured by letter of credit(2)(3)		―			55
			7,086			6,048
Current portion of long-term debt			(848	)		(104	)
Unamortized discount on long-term debt			(10	)		(9	)
Unamortized premium on long-term debt			5			7
Unamortized debt issuance costs			(35	)		(30	)
Total other Sempra Energy			6,198			5,912
Total Sempra Energy Consolidated		$	13,134		$	12,086

(1)	As adjusted for the retrospective adoption of ASU 2015-03.
(2)	Callable long-term debt not subject to make-whole provisions.
(3)	Early redemption in 2015.
(4)	We discuss this lease in Note 15.

MATURITIES OF LONG-TERM DEBT(1)
(Dollars in millions)
										Total
							Other			Sempra
							Sempra			Energy
	SDG&E			SoCalGas			Energy			Consolidated
2016		$	46		$	8		$	843		$	897
2017			186			―			668			854
2018			207			500			662			1,369
2019			320			―			534			854
2020			36			―			932			968
Thereafter			3,509			2,005			3,307			8,821
Total		$	4,304		$	2,513		$	6,946		$	13,763

(1)

Excludes capital lease obligations, build-to-suit lease and market value adjustments for interest rate swaps.

Various long-term obligations totaling $6.8 billion at Sempra Energy at December 31, 2015 are unsecured. This includes unsecured long-term obligations totaling $13 million at SoCalGas. There were no unsecured long-term obligations at SDG&E.

CALLABLE LONG-TERM DEBT

At the option of Sempra Energy, SDG&E and SoCalGas, certain debt at December 31, 2015 is callable subject to premiums:

CALLABLE LONG-TERM DEBT
(Dollars in millions)
										Total
							Other			Sempra
							Sempra			Energy
	SDG&E			SoCalGas			Energy			Consolidated
Not subject to make-whole provisions		$	517		$	8		$	285		$	810
Subject to make-whole provisions			3,472			2,505			6,661			12,638

In addition, the OMEC LLC project financing loan discussed in Note 1, with $315 million of outstanding borrowings at December 31, 2015, may be prepaid at the borrowers’ option.

FIRST MORTGAGE BONDS

The California Utilities issue first mortgage bonds secured by a lien on utility plant. The California Utilities may issue additional first mortgage bonds if in 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 $4.1 billion of first mortgage bonds at SDG&E and $0.8 billion at SoCalGas at December 31, 2015.

In March 2015, SDG&E publicly offered and sold $140 million of first mortgage bonds maturing in 2017 at a variable rate of three-month LIBOR plus 0.20 percent (0.68 percent at December 31, 2015) and $250 million of 1.914-percent amortizing first mortgage bonds maturing in 2022. SDG&E used the proceeds from the offering to repay outstanding commercial paper and for other general corporate purposes.

In June 2015, SoCalGas publicly offered and sold $250 million of 1.55-percent and $350 million of 3.20-percent first mortgage bonds maturing in 2018 and 2025, respectively. SoCalGas used the proceeds from the offering to repay outstanding commercial paper and for other general corporate purposes.

INDUSTRIAL DEVELOPMENT BONDS

Sempra Natural Gas

To secure an approved exemption from sales and use tax, Sempra Natural Gas had incurred $259 million, out of a maximum available $265 million, between the years of 2009 through 2015, of long-term debt related to the construction and equipping of its Mississippi Hub natural gas storage facility. The debt was 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 had interest rates of 4.5 percent and were due on July 1, 2024. Sempra Natural Gas redeemed $180 million in December 2011 and the remaining $79 million in June 2015.

In December 2015, Sempra Natural Gas redeemed, prior to their August 2037 maturity, $55 million of industrial development bonds payable at variable rates at Bay Gas Storage Company, Ltd.

OTHER LONG-TERM DEBT

Sempra Energy

In March 2015, Sempra Energy publicly offered and sold $500 million of 2.40-percent, fixed-rate notes maturing in 2020. In November 2015, Sempra Energy publicly offered and sold $400 million of 2.85-percent fixed-rate notes maturing in 2020 and $350 million of 3.75-percent fixed-rate notes maturing in 2025. Sempra Energy used the proceeds from these offerings to repay outstanding commercial paper and for general corporate purposes.

SDG&E

In August 2015, SDG&E redeemed, prior to maturity, certain outstanding long-term debt instruments with a total principal amount of $169 million. The coupon rates of these instruments ranged from 4.9 percent to 5.5 percent, with maturities ranging from 2021 to 2027.

Sempra South American Utilities

Luz del Sur has outstanding corporate bonds and bank loans which are denominated in the local currency. During 2015, Luz del Sur publicly offered and sold $25 million of corporate bonds at 8.75 percent maturing in 2026. Additionally, Luz del Sur drew bank loans in 2015 as follows:

2015 BANK LOAN DRAWS – LUZ DEL SUR
(Dollars in millions)
	Amount at
Month issued	issuance			Interest rate			Maturity date
May		$	13		5.18	%	May 2018
June			22		5.18	%	June 2018
August			9		6.70	%	February 2018
November			15		6.55	%	November 2017

INTEREST RATE SWAPS

We discuss our fair value and cash flow hedging interest rate swaps in Note 9.

NOTE 6. 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,
	2015		2014		2013
Sempra Energy Consolidated:
U.S. federal statutory income tax rate	35	%	35	%	35	%
Utility depreciation	5		5		4
U.S. tax on repatriation of foreign earnings	1		2		―
Income tax restructuring related to IEnova stock offerings	―		―		4
State income taxes, net of federal income tax benefit	1		―		1
Utility repairs expenditures	(5)		(5)		(5)
Tax credits	(4)		(4)		(3)
Self-developed software expenditures	(3)		(3)		(3)
Resolution of prior years’ income tax items	(3)		(1)		(3)
Non-U.S. earnings taxed at lower statutory income tax rates	(2)		(2)		(3)
Allowance for equity funds used during construction	(2)		(2)		(1)
Foreign exchange and inflation effects	(2)		(2)		―
International tax reform	―		(1)		1
Other, net	(1)		(2)		(1)
Effective income tax rate	20	%	20	%	26	%
SDG&E:
U.S. federal statutory income tax rate	35	%	35	%	35	%
State income taxes, net of federal income tax benefit	5		5		3
Depreciation	4		4		5
SONGS tax regulatory asset write-off	―		2		―
Repairs expenditures	(4)		(4)		(4)
Self-developed software expenditures	(3)		(3)		(3)
Allowance for equity funds used during construction	(2)		(2)		(2)
Resolution of prior years’ income tax items	(2)		(2)		(1)
Variable interest entity	(1)		(1)		(1)
Other, net	―		―		(1)
Effective income tax rate	32	%	34	%	31	%
SoCalGas:
U.S. federal statutory income tax rate	35	%	35	%	35	%
Depreciation	8		8		6
State income taxes, net of federal income tax benefit	4		4		4
Repairs expenditures	(10)		(9)		(9)
Self-developed software expenditures	(6)		(5)		(6)
Resolution of prior years’ income tax items	(3)		(2)		(5)
Allowance for equity funds used during construction	(2)		(2)		(1)
Other, net	(1)		―		―
Effective income tax rate	25	%	29	%	24	%

In 2015, 2014 and 2013, 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.

Foreign exchange and inflation effects for Sempra Energy Consolidated in 2015 and 2014 are primarily due to significant devaluation of the Mexican peso against the U.S. dollar.

In 2014, our effective income tax rate was affected by a $25 million state tax benefit due to the release of Louisiana state valuation allowance against a deferred tax asset associated with Cameron LNG developments. This benefit is included in “State Income Taxes, Net of Federal Income Tax Benefit” in the Sempra Energy Consolidated table above.

In addition, the effective income tax rates for Sempra Energy Consolidated and SDG&E were impacted in 2014 by a $17 million charge to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS that we discuss in Note 13. This charge is included in “Resolution of Prior Years’ Income Tax Items” in the Sempra Energy Consolidated table above.

Furthermore, our effective income tax rate was affected by international tax reform in both Peru and Chile in 2014 and in Mexico in 2013.

In 2013, our effective income tax rate was affected by $63 million of income tax expense recorded in the first quarter of 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings.

Utility repairs expenditures significantly affecting the effective income tax rates for Sempra Energy Consolidated, SDG&E and SoCalGas in 2015, 2014 and 2013 are due to a change in 2012 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. 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.

For SDG&E and SoCalGas, 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 impacts the current effective income tax rate. As a result, 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

§	utility self-developed software expenditures

§	depreciation on a certain portion of utility plant assets

§	state income taxes

The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico has similar flow-through treatment.

We use the deferral method for investment tax credits (ITC). For certain solar and wind generating assets placed into service during 2012, we elected to seek cash grants rather than ITC for which the projects also qualify. Accordingly, cash grant accounting was 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 by 50 percent for grants and not at all for ITC.

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 Consolidated are as follows:

GEOGRAPHIC COMPONENTS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
U.S.		$	1,189		$	1,014		$	941
Non-U.S.			515			510			489
Total		$	1,704		$	1,524		$	1,430

The components of income tax expense are as follows:

INCOME TAX EXPENSE (BENEFIT)
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Sempra Energy Consolidated:
Current:
U.S. federal	$	3		$	(10	)	$	(70	)
U.S. state		(24	)		(7	)		(5	)
Non-U.S.		123			171			107
Total		102			154			32
Deferred:
U.S. federal		242			237			275
U.S. state		34			4			15
Non-U.S.		(32	)		(91	)		48
Total		244			150			338
Deferred investment tax credits		(5	)		(4	)		(4	)
Total income tax expense	$	341		$	300		$	366
SDG&E:
Current:
U.S. federal	$	12		$	(5	)	$	9
U.S. state		77			52			11
Total		89			47			20
Deferred:
U.S. federal		233			220			149
U.S. state		(35	)		5			24
Total		198			225			173
Deferred investment tax credits		(3	)		(2	)		(2	)
Total income tax expense	$	284		$	270		$	191
SoCalGas:
Current:
U.S. federal	$	(1	)	$	2		$	4
U.S. state		12			7			(5	)
Total		11			9			(1	)
Deferred:
U.S. federal		122			117			103
U.S. state		7			15			16
Total		129			132			119
Deferred investment tax credits		(2	)		(2	)		(2	)
Total income tax expense	$	138		$	139		$	116

We show the components of deferred income taxes at December 31 for Sempra Energy Consolidated, SDG&E and SoCalGas in the tables below:

DEFERRED INCOME TAXES FOR SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	December 31,
	2015		2014
Deferred income tax liabilities:
Differences in financial and tax bases of depreciable and amortizable assets	$	4,487	$	4,074
Regulatory balancing accounts		745		915
Property taxes		61		57
Differences in financial and tax bases of partnership interests(1)		796		650
Other deferred income tax liabilities		100		53
Total deferred income tax liabilities		6,189		5,749
Deferred income tax assets:
Tax credits		381		276
Net operating losses		1,856		1,908
Compensation-related items		252		244
Postretirement benefits		446		433
Other deferred income tax assets		179		156
Litigation and other accruals not yet deductible		72		73
Deferred income tax assets before valuation allowances		3,186		3,090
Less: valuation allowances		34		39
Total deferred income tax assets		3,152		3,051
Net deferred income tax liability(2)	$	3,037	$	2,698

(1)	Amounts primarily represent differences in financial and tax bases of depreciable and amortizable assets within our partnerships.
(2)	At December 31, 2015, the net deferred income tax liability includes $120 million recorded as a noncurrent asset in Sundry on the Consolidated Balance Sheet.

DEFERRED INCOME TAXES FOR SDG&E AND SOCALGAS
(Dollars in millions)
	SDG&E				SoCalGas
	December 31,				December 31,
	2015		2014		2015		2014
Deferred income tax liabilities:
Differences in financial and tax bases of
utility plant and other assets	$	2,392	$	2,181	$	1,473	$	1,194
Regulatory balancing accounts		234		441		515		481
Property taxes		42		39		20		18
Other		5		5		5		10
Total deferred income tax liabilities		2,673		2,666		2,013		1,703
Deferred income tax assets:
Net operating losses		―		297		110		64
Postretirement benefits		90		85		268		261
Compensation-related items		11		8		42		40
State income taxes		46		27		13		11
Litigation and other accruals not yet deductible		36		39		20		23
Other		18		36		28		39
Total deferred income tax assets		201		492		481		438
Net deferred income tax liability	$	2,472	$	2,174	$	1,532	$	1,265

At December 31, 2015, Sempra Energy’s U.S. subsidiaries had $4.9 billion of unused U.S. federal consolidated NOLs that will begin to expire in 2031, $279 million of unused U.S. federal consolidated general business tax credits that will begin to expire in 2032 and $58 million of unused foreign tax credits that will begin to expire in 2024. Included in the NOL amount is $265 million of excess tax deductions related to employee stock expense for which a benefit will be recorded to additional paid in capital when realized. When assessing whether a tax benefit relating to employee stock expense has been realized, we follow the tax law ordering method, under which current year share-based compensation deductions are assumed to be utilized before net operating loss carryforwards and other tax attributes. We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not basis.

At December 31, 2015, SoCalGas had $363 million of unused U.S. federal NOLs which begin to expire in 2032 and $7 million of unused U.S. federal general business tax credits which begin to expire in 2031. We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not basis.

At December 31, 2015, Sempra Energy’s U.S. subsidiaries had $2.8 billion of unused U.S. state NOLs, primarily in Alabama, California and Louisiana. These U.S. state NOLs expire between 2016 and 2035. Included in the NOL amount is $222 million of excess tax deductions related to employee stock expense for which a benefit will be recorded to additional paid in capital when realized. Sempra Energy’s U.S. subsidiaries also had $44 million of unused U.S. state general business tax credits that begin to expire in 2016. We have not recorded deferred income tax benefits on a portion of Sempra Energy’s total U.S. state NOLs and tax credits because we currently believe they will not be realized on a more-likely-than-not basis, as discussed below.

At December 31, 2015, Sempra Energy’s non-U.S. subsidiaries had $468 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 companies in Mexico and the Netherlands. The carryforward periods for our non-U.S. unused NOLs expire between 2016 and 2025. We have not recorded deferred income tax benefits on a portion of Sempra Energy’s total non-U.S. NOLs because we currently believe they will not be realized on a more-likely-than-not basis, as discussed below.

At December 31, 2015, Sempra Energy 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 above, that we currently do not believe will be realized on a more-likely-than-not basis. Of Sempra Energy’s total valuation allowance of $34 million at December 31, 2015, $6 million is related to non-U.S. NOLs and $28 million to U.S. state NOLs and tax credits. Of Sempra Energy’s total valuation allowance of $39 million at December 31, 2014, $8 million is related to non U.S. NOLs and $31 million to U.S. state NOLs. The total valuation allowance decreased in 2015 primarily due to release of a valuation allowance against a state capital loss deferred tax asset. Sempra Natural Gas and its project partners are currently developing a natural gas liquefaction export facility at the Cameron LNG terminal in Louisiana. In 2014, we released $25 million of Louisiana state valuation allowance against a deferred tax asset associated with Cameron LNG developments.

At December 31, 2015, Sempra Energy had not recognized a U.S. deferred income tax liability related to a $3.9 billion basis difference between its financial statement and income tax investment amount in its non-U.S. subsidiaries and non-U.S. corporate joint ventures. This basis difference consists of cumulative undistributed earnings that we expect to reinvest indefinitely outside of the U.S. 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.

Following is a summary of unrecognized income tax benefits:

SUMMARY OF UNRECOGNIZED INCOME TAX BENEFITS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Sempra Energy Consolidated:
Total	$	87		$	117		$	90
Of the total, amounts related to tax positions that,
if recognized in future years, would
decrease the effective tax rate(1)	$	(83	)	$	(114	)	$	(86	)
increase the effective tax rate(1)		32			21			19
SDG&E:
Total	$	20		$	14		$	17
Of the total, amounts related to tax positions that,
if recognized in future years, would
decrease the effective tax rate(1)	$	(16	)	$	(11	)	$	(14	)
increase the effective tax rate(1)		11			6			11
SoCalGas:
Total	$	27		$	19		$	13
Of the total, amounts related to tax positions that,
if recognized in future years, would
decrease the effective tax rate(1)	$	(27	)	$	(19	)	$	(13	)
increase the effective tax rate(1)		21			15			8

(1)

Includes temporary book and tax differences that are treated as flow-through for ratemaking purposes, as discussed above.

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)
	2015			2014			2013
Sempra Energy Consolidated:
Balance as of January 1	$	117		$	90		$	82
Increase in prior period tax positions		10			37			26
Decrease in prior period tax positions		―			―			(24	)
Increase in current period tax positions		8			5			7
Settlements with taxing authorities		(48	)		(15	)		(1	)
Balance as of December 31	$	87		$	117		$	90
SDG&E:
Balance as of January 1	$	14		$	17		$	12
Increase in prior period tax positions		5			2			7
Decrease in prior period tax positions		―			―			(4	)
Increase in current period tax positions		2			―			2
Settlements with taxing authorities		(1	)		(5	)		―
Balance as of December 31	$	20		$	14		$	17
SoCalGas:
Balance as of January 1	$	19		$	13		$	5
Increase in prior period tax positions		2			2			4
Increase in current period tax positions		6			4			5
Settlements with taxing authorities		―			―			(1	)
Balance as of December 31	$	27		$	19		$	13

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,
	2015			2014			2013
Sempra Energy Consolidated:
Expiration of statutes of limitations on tax assessments	$	(2	)	$	―		$	(7	)
Potential resolution of audit issues with various
U.S. federal, state and local and non-U.S. taxing authorities		(32	)		(61	)		(63	)
	$	(34	)	$	(61	)	$	(70	)
SDG&E:
Expiration of statutes of limitations on tax assessments	$	(1	)	$	―		$	―
Potential resolution of audit issues with various
U.S. federal, state and local taxing authorities		(8	)		(9	)		(14	)
	$	(9	)	$	(9	)	$	(14	)
SoCalGas:
Potential resolution of audit issues with various
U.S. federal, state and local taxing authorities	$	(22	)	$	(15	)	$	(11	)

Amounts accrued for interest and penalties associated with unrecognized income tax benefits are included in income tax expense on the Consolidated Statements of Operations. We summarize the amounts accrued at December 31 on the Consolidated Balance Sheets for interest and penalties associated with unrecognized income tax benefits and the related expense in the table below.

INTEREST AND PENALTIES ASSOCIATED WITH UNRECOGNIZED INCOME TAX BENEFITS
(Dollars in millions)
	Interest and penalties												Accrued interest and penalties
	Years ended December 31,												December 31,
	2015				2014				2013				2015			2014
Sempra Energy Consolidated:
Interest (income) expense		$	(2	)		$	(4	)		$	1			$	1		$	―
Penalties			―				(3	)			―				―			―
SDG&E:
Interest income		$	―			$	(1	)		$	―			$	―		$	―
SoCalGas:
Interest income		$	―			$	―			$	(1	)		$	―		$	―

Penalties accrued and expensed at SDG&E and SoCalGas in all periods presented were zero or negligible.

INCOME TAX AUDITS

Sempra Energy is subject to U.S. federal income tax as well as income tax of multiple state and non-U.S. jurisdictions. We remain subject to examination for U.S. federal tax years after 2010. We are subject to examination by major state tax jurisdictions for tax years after 2008. Certain major non-U.S. income tax returns for tax years 2008 through the present are open to examination.

In addition, we filed federal refund claims for the 2009 and 2010 tax years during 2015; however, no additional tax may be assessed by the IRS for pre-2011 tax years. We have also filed state refund claims for tax years back to 2006. The pre-2009 tax years for our major state tax jurisdictions are closed to new issues, therefore, no additional tax may be assessed by the taxing authorities for these tax 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 tax years after 2010 and by state tax jurisdictions for tax years after 2008.

NOTE 7. 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 traditional defined benefit and cash balance plans, including separate plans for SDG&E and SoCalGas, which collectively cover all eligible employees, including members of the Sempra Energy board of directors who were participants in a predecessor plan on or before June 1, 1998. Pension benefits under the traditional defined benefit plans are based on service and final average earnings, while the cash balance plans provide benefits using a career average earnings methodology.

IEnova has an unfunded noncontributory defined benefit plan covering all employees. Chilquinta Energía has an unfunded noncontributory defined benefit plan covering all employees hired before October 1, 1981. In addition, IEnova and Chilquinta Energía have 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 earnings.

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 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.

RABBI TRUST

In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra Energy maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $464 million and $512 million at December 31, 2015 and 2014, respectively.

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

Benefit Plan Amendments Affecting 2015

During 2015, executive participants in a company nonqualified pension plan became eligible in this same plan for Supplemental Executive Retirement Plan benefits. Consistent with past practice, this was treated as a plan amendment and increased the recorded pension liability by $5 million at Sempra Energy Consolidated and $3 million at SoCalGas.

Effective January 1, 2016, the point of service medical benefit provided to retirees under the age of 65 at our domestic companies, except the represented retirees at SDG&E and retirees enrolled in one of the high deductible medical plans at SoCalGas, is no longer provided by the PBOP plans of the respective companies. This change resulted in a decrease in other postretirement benefit obligations of $9 million at each of Sempra Energy Consolidated and SoCalGas, and by a negligible amount at SDG&E.

Benefit Plan Amendments Affecting 2014

During 2014, executive participants in a company nonqualified pension plan became eligible in this same plan for Supplemental Executive Retirement Plan benefits. Consistent with past practice, this was treated as a plan amendment and increased the recorded pension liability by $4 million at Sempra Energy Consolidated.

Effective January 1, 2014, a new high deductible medical benefit was provided to all SDG&E and SoCalGas retirees under the age of 65, except the represented retirees at SoCalGas, participating in the companies’ PBOP plans. This benefit replaced a previous benefit provided by the SDG&E plans and was an added benefit in the SoCalGas plan. These changes resulted in an increase in other postretirement benefit obligations by a negligible amount at SDG&E and by $1 million at each of Sempra Energy Consolidated and SoCalGas.

Special Termination Benefits Affecting 2014

At SDG&E in 2014, all nonrepresented employees age 62 with 5 years of service and all other nonrepresented employees age 55 with 10 years of service that retired under the Voluntary Retirement Enhancement Program offered in that year received an additional postretirement health benefit in the form of a $50,000 Health Reimbursement Account (HRA). In accordance with U.S. GAAP, we elected to treat the benefit obligation attributable to the HRA as special termination benefits. This resulted in increases to the recorded liability for other postretirement benefits of approximately $5 million for each of Sempra Energy Consolidated and SDG&E in 2014.

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 2015 and 2014, and a statement of the funded status at December 31, 2015 and 2014:

PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2015			2014			2015			2014
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1	$	3,839		$	3,459		$	1,115		$	973
Service cost		114			101			26			24
Interest cost		154			161			44			49
Contributions from plan participants		―			―			19			17
Actuarial (gain) loss		(180	)		441			(172	)		105
Benefit payments		(273	)		(217	)		(60	)		(58	)
Plan amendments		5			4			(9	)		1
Special termination benefits		―			―			―			5
Settlements and curtailments		(10	)		(110	)		―			(1	)
Net obligation at December 31		3,649			3,839			963			1,115

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1		2,807			2,789			1,054			1,012
Actual return on plan assets		(73	)		217			(21	)		67
Employer contributions		33			128			11			16
Contributions from plan participants		―			―			19			17
Benefit payments		(273	)		(217	)		(60	)		(58	)
Settlements		(10	)		(110	)		―			―
Fair value of plan assets at December 31		2,484			2,807			1,003			1,054
Funded status at December 31	$	(1,165	)	$	(1,032	)	$	40		$	(61	)
Net recorded (liability) asset at December 31	$	(1,165	)	$	(1,032	)	$	40		$	(61	)

PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
SAN DIEGO GAS & ELECTRIC COMPANY
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2015			2014			2015			2014
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1	$	1,011		$	939		$	200		$	171
Service cost		29			30			7			7
Interest cost		39			43			8			9
Contributions from plan participants		―			―			7			6
Actuarial (gain) loss		(52	)		101			(43	)		15
Benefit payments		(56	)		(25	)		(14	)		(13	)
Special termination benefits		―			―			―			5
Settlements		―			(87	)		―			―
Transfer of liability (to) from other plans		(6	)		10			―			―
Net obligation at December 31		965			1,011			165			200

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1		828			819			164			146
Actual return on plan assets		(24	)		63			(3	)		11
Employer contributions		2			56			7			14
Contributions from plan participants		―			―			7			6
Benefit payments		(56	)		(25	)		(14	)		(13	)
Settlements		―			(87	)		―			―
Transfer of assets from other plans		2			2			―			―
Fair value of plan assets at December 31		752			828			161			164
Funded status at December 31	$	(213	)	$	(183	)	$	(4	)	$	(36	)
Net recorded liability at December 31	$	(213	)	$	(183	)	$	(4	)	$	(36	)

PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
SOUTHERN CALIFORNIA GAS COMPANY
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2015			2014			2015			2014
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1	$	2,398		$	2,110		$	866		$	753
Service cost		74			60			17			16
Interest cost		98			100			34			38
Contributions from plan participants		―			―			12			11
Actuarial (gain) loss		(131	)		300			(125	)		90
Benefit payments		(187	)		(163	)		(43	)		(43	)
Plan amendments		3			―			(9	)		1
Settlements		―			(10	)		―			―
Transfer of liability from other plans		―			1			―			―
Net obligation at December 31		2,255			2,398			752			866

CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1		1,763			1,758			870			848
Actual return on plan assets		(45	)		138			(18	)		54
Employer contributions		6			39			1			―
Contributions from plan participants		―			―			12			11
Benefit payments		(187	)		(163	)		(43	)		(43	)
Settlements		―			(10	)		―			―
Transfer of assets from other plans		―			1			―			―
Fair value of plan assets at December 31		1,537			1,763			822			870
Funded status at December 31	$	(718	)	$	(635	)	$	70		$	4
Net recorded (liability) asset at December 31	$	(718	)	$	(635	)	$	70		$	4

New mortality table studies were released by the Society of Actuaries during 2014 that significantly increased life expectancy assumptions, and during 2015 that consisted of a new mortality improvement projection scale. We have incorporated these assumptions, adjusted for the Sempra Energy companies’ actual mortality experience, in our calculations for each of those years.

In 2015, the actuarial gains for pension plans were primarily due to:

§	an increase in weighted-average discount rates;

§	changes in salary scale at SoCalGas;

§	updated mortality rates;

§	a change in the rate used to convert annuity benefits to lump sums; and

§	the impact of updated census data at SDG&E; offset by

§	the impact of updated census data at Sempra Energy Consolidated and SoCalGas; and

§	changes in anticipated retirement rates.

In 2015, the actuarial gains for other postretirement benefit plans were primarily due to:

§	the impact of updated census data;

§	changes in termination and retirement rates;

§	an increase in weighted-average discount rates;

§	a decrease in the actual versus expected 2016 claims costs; and

§	updated mortality rates; offset by

§	changes in health care cost trend rates; and

§	changes in salary scale at SoCalGas.

In 2014, the actuarial losses for pension plans were primarily due to:

§	a decrease in weighted-average discount rates;

§	updated mortality rates; and

§	a change in the rate used to convert annuity benefits to lump sums at SoCalGas; offset by

§	the impact of updated census data at SoCalGas; and

§	a decrease in the cash balance interest crediting rate.

In 2014, the actuarial losses for other postretirement benefit plans were primarily due to:

§	a decrease in weighted-average discount rates;

§	updated mortality rates; and

§	the impact of updated census data at SDG&E and SoCalGas; offset by

§	a decrease in anticipated retiree and spousal participation rates.

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. Our funded pension and other postretirement benefit plans use the asset smoothing method, except for those at SDG&E and the other postretirement benefit plan at Mobile Gas. 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 Consolidated, 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 IRS. 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 rate-regulated entities.

The net (liability) asset is included in the following categories on the Consolidated Balance Sheets at December 31:

PENSION AND OTHER POSTRETIREMENT BENEFIT OBLIGATIONS, NET OF PLAN ASSETS AT DECEMBER 31
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	2015			2014			2015			2014
Sempra Energy Consolidated:
Noncurrent assets	$	―		$	―		$	70		$	4
Current liabilities		(43	)		(33	)		―			―
Noncurrent liabilities		(1,122	)		(999	)		(30	)		(65	)
Net recorded (liability) asset	$	(1,165	)	$	(1,032	)	$	40		$	(61	)
SDG&E:
Current liabilities	$	(5	)	$	(3	)	$	―		$	―
Noncurrent liabilities		(208	)		(180	)		(4	)		(36	)
Net recorded liability	$	(213	)	$	(183	)	$	(4	)	$	(36	)
SoCalGas:
Noncurrent assets	$	―		$	―		$	70		$	4
Current liabilities		(2	)		(2	)		―			―
Noncurrent liabilities		(716	)		(633	)		―			―
Net recorded (liability) asset	$	(718	)	$	(635	)	$	70		$	4

Amounts recorded in accumulated other comprehensive income (loss) at December 31, 2015 and 2014, 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
	2015			2014			2015		2014
Sempra Energy Consolidated:
Net actuarial (loss) gain	$	(84	)	$	(82	)	$	2	$	(1	)
Prior service cost		(5	)		(2	)		―		―
Total	$	(89	)	$	(84	)	$	2	$	(1	)
SDG&E:
Net actuarial loss	$	(8	)	$	(13	)
Prior service credit		―			1
Total	$	(8	)	$	(12	)
SoCalGas:
Net actuarial loss	$	(4	)	$	(5	)
Prior service (cost) credit		(1	)		1
Total	$	(5	)	$	(4	)

The accumulated benefit obligation for defined benefit pension plans at December 31, 2015 and 2014 was as follows:

ACCUMULATED BENEFIT OBLIGATION
(Dollars in millions)
	Sempra Energy Consolidated				SDG&E				SoCalGas
	2015		2014		2015		2014		2015		2014
Accumulated benefit obligation	$	3,397	$	3,555	$	939	$	978	$	2,056	$	2,182

Sempra Energy, SDG&E, SoCalGas and Mobile Gas each have a funded pension plan. We also have unfunded pension plans at Sempra Energy, SDG&E, SoCalGas, IEnova and Chilquinta Energía. The following table shows the obligations of funded pension plans with benefit obligations in excess of plan assets at December 31:

OBLIGATIONS OF FUNDED PENSION PLANS
(Dollars in millions)
	2015		2014
Sempra Energy Consolidated:
Projected benefit obligation	$	3,410	$	3,592
Accumulated benefit obligation		3,183		3,343
Fair value of plan assets		2,484		2,807
SDG&E:
Projected benefit obligation	$	927	$	964
Accumulated benefit obligation		906		937
Fair value of plan assets		752		828
SoCalGas:
Projected benefit obligation	$	2,236	$	2,379
Accumulated benefit obligation		2,039		2,166
Fair value of plan assets		1,537		1,763

Net Periodic Benefit Cost

The following three tables provide the components of net periodic benefit cost and pretax amounts recognized in other comprehensive income (loss) for the years ended December 31:

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OTHER COMPREHENSIVE INCOME (LOSS)
SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension benefits									Other postretirement benefits
	2015			2014			2013			2015			2014			2013
NET PERIODIC BENEFIT COST
Service cost	$	114		$	101		$	109		$	26		$	24		$	28
Interest cost		154			161			148			44			49			44
Expected return on assets		(173	)		(171	)		(162	)		(68	)		(63	)		(58	)
Amortization of:
Prior service cost (credit)		11			11			4			(4	)		(5	)		(4	)
Actuarial loss		38			18			54			―			―			7
Settlement and curtailment charges		4			31			2			―			(1	)		―
Special termination benefits		―			―			―			―			5			5
Regulatory adjustment		(110	)		(31	)		(20	)		12			6			6
Total net periodic benefit cost		38			120			135			10			15			28

CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS
RECOGNIZED IN OTHER COMPREHENSIVE INCOME (LOSS)
Net loss (gain)		17			38			(30	)		(4	)		1			(8	)
Prior service cost		4			4			1			―			―			―
Amortization of actuarial loss		(14	)		(23	)		(9	)		―			―			(1	)
Total recognized in other comprehensive income (loss)		7			19			(38	)		(4	)		1			(9	)
Total recognized in net periodic benefit cost and other comprehensive income (loss)	$	45		$	139		$	97		$	6		$	16		$	19

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OTHER COMPREHENSIVE INCOME (LOSS)
SAN DIEGO GAS & ELECTRIC COMPANY
(Dollars in millions)
	Pension benefits									Other postretirement benefits
	2015			2014			2013			2015			2014			2013
NET PERIODIC BENEFIT COST
Service cost	$	29		$	30		$	32		$	7		$	7		$	8
Interest cost		39			43			41			8			9			8
Expected return on assets		(54	)		(55	)		(52	)		(11	)		(10	)		(8	)
Amortization of:
Prior service cost		8			2			2			3			2			4
Actuarial loss		2			4			14			―			―			―
Settlement charge		―			19			1			―			―			―
Special termination benefits		―			―			―			―			5			2
Regulatory adjustment		(20	)		12			14			―			1			―
Total net periodic benefit cost		4			55			52			7			14			14

CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS
RECOGNIZED IN OTHER COMPREHENSIVE INCOME (LOSS)
Net (gain) loss		(6	)		8			(2	)		―			―			―
Amortization of actuarial loss		(1	)		(3	)		(1	)		―			―			―
Total recognized in other comprehensive (loss) income		(7	)		5			(3	)		―			―			―
Total recognized in net periodic benefit cost and other comprehensive (loss) income	$	(3	)	$	60		$	49		$	7		$	14		$	14

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OTHER COMPREHENSIVE INCOME (LOSS)
SOUTHERN CALIFORNIA GAS COMPANY
(Dollars in millions)
	Pension benefits									Other postretirement benefits
	2015			2014			2013			2015			2014			2013
NET PERIODIC BENEFIT COST
Service cost	$	74		$	60		$	67		$	17		$	16		$	17
Interest cost		98			100			90			34			38			34
Expected return on assets		(106	)		(104	)		(98	)		(56	)		(51	)		(48	)
Amortization of:
Prior service cost (credit)		9			9			2			(7	)		(8	)		(8	)
Actuarial loss		21			6			31			―			―			6
Settlement charge		―			4			―			―			―			―
Special termination benefits		―			―			―			―			―			2
Regulatory adjustment		(90	)		(43	)		(34	)		12			5			6
Total net periodic benefit cost		6			32			58			―			―			9

CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS
RECOGNIZED IN OTHER COMPREHENSIVE INCOME (LOSS)
Net loss		―			5			3			―			―			―
Prior service cost		2			―			―			―			―			―
Amortization of actuarial loss		―			(5	)		(1	)		―			―			―
Total recognized in other comprehensive income		2			―			2			―			―			―
Total recognized in net periodic benefit cost and other comprehensive income	$	8		$	32		$	60		$	―		$	―		$	9

The estimated net loss for the pension and other postretirement benefit plans that will be amortized from accumulated other comprehensive income (loss) into net periodic benefit cost in 2016 is $8 million for Sempra Energy Consolidated, $1 million for SDG&E and a negligible amount for SoCalGas. The estimated prior service cost that will be similarly amortized in 2016 is $1 million for Sempra Energy Consolidated and negligible amounts for SDG&E and SoCalGas.

Assumptions for Pension and Other Postretirement Benefit Plans

Benefit Obligation and Net Periodic Benefit Cost

Except for the IEnova and 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 IEnova by constructing a synthetic government zero coupon bond yield curve from the available market data, based on duration matching, and we add a risk spread to allow for the yields of high-quality corporate bonds. 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. These methods for developing the discount rate are 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.

We amortize prior service cost using straight line amortization over average future service (or average expected lifetime for plans where participants are substantially inactive employees), which is an alternative method allowed under GAAP.

The significant assumptions affecting benefit obligation and net periodic benefit cost are as follows:

WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE BENEFIT OBLIGATION AT DECEMBER 31

	Pension benefits				Other postretirement benefits
	2015		2014		2015		2014
Sempra Energy Consolidated:
Discount rate	4.46	%	4.09	%	4.49	%	4.15	%
Rate of compensation increase	2.00-10.00		3.50-10.00		2.00-10.00		3.50-10.00
SDG&E:
Discount rate	4.35	%	4.00	%	4.50	%	4.15	%
Rate of compensation increase	2.00-10.00		3.50-10.00		2.00-10.00		3.50-10.00
SoCalGas:
Discount rate	4.50	%	4.15	%	4.50	%	4.15	%
Rate of compensation increase	2.00-10.00		3.50-10.00		2.00-10.00		3.50-10.00

WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COST FOR YEARS ENDED DECEMBER 31

	Pension benefits						Other postretirement benefits
	2015		2014		2013		2015		2014		2013
Sempra Energy Consolidated:
Discount rate	4.09	%	4.85	%	4.04	%	4.15	%	4.95	%	4.09	%
Expected return on plan assets	7.00		7.00		7.00		6.98		6.97		6.96
Rate of compensation increase	2.00-10.00		3.50-10.00		3.50-9.50		2.00-10.00		3.50-10.00		3.50-9.50
SDG&E:
Discount rate	4.00	%	4.69	%	3.94	%	4.15	%	5.00	%	4.10	%
Expected return on plan assets	7.00		7.00		7.00		6.91		6.88		6.81
Rate of compensation increase	2.00-10.00		3.50-10.00		3.50-9.50		2.00-10.00		3.50-10.00		N/A
SoCalGas:
Discount rate	4.15	%	4.94	%	4.10	%	4.15	%	4.95	%	4.10	%
Expected return on plan assets	7.00		7.00		7.00		7.00		7.00		7.00
Rate of compensation increase	2.00-10.00		3.50-10.00		3.50-9.50		2.00-10.00		3.50-10.00		3.50-9.50

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:

ASSUMED HEALTH CARE COST TREND RATES AT DECEMBER 31

		Other postretirement benefit plans(1)
		Pre-65 retirees						Retirees aged 65 years and older
		2015		2014		2013		2015		2014		2013
Health care cost trend rate assumed for next year		8.10	%	7.75	%	8.25	%	5.50	%	5.25	%	5.50	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)		5.00	%	5.00	%	5.00	%	4.50	%	4.50	%	4.50	%
Year the rate reaches the ultimate trend		2022		2020		2020		2022		2020		2020
(1)	Excludes Mobile Gas Plan. For Mobile Gas, the health care cost trend rate assumed for next year for all retirees was 8.10 percent, 7.75 percent and 7.50 percent in 2015, 2014 and 2013, respectively; the ultimate trend was 5.00 percent in 2015, 2014 and 2013; and the year the rate reaches the ultimate trend was 2022, 2020 and 2019 in 2015, 2014 and 2013, respectively. For Chilquinta Energía, the health care cost trend rate assumed for next year and all subsequent years was 3.00 percent in each of 2015, 2014 and 2013.

A one-percent change in assumed health care cost trend rates would have had the following effects in 2015:


EFFECT OF ONE-PERCENT CHANGE IN ASSUMED HEALTH CARE COST TREND RATES
(Dollars in millions)
	Sempra Energy
	Consolidated				SDG&E				SoCalGas
	1%		1%		1%		1%		1%		1%
	increase		decrease		increase		decrease		increase		decrease
Effect on total of service and interest
cost components of net periodic
postretirement health care benefit cost	$	7	$	(5)	$	1	$	(1)	$	5	$	(4)
Effect on the health care component of the
accumulated other postretirement
benefit obligations		74		(62)		5		(4)		67		(55)

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 benefit plans. Other than through indexing strategies, 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’ target asset allocations are

§	38 percent domestic equity

§	26 percent international equity

§	18 percent long credit

§	5 percent global high yield credit

§	5 percent real assets

§	4 percent STRIPS

§	4 percent long government

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.

In accordance with the Sempra Energy pension investment guidelines, derivative financial instruments may be used by the pension master trust’s equity and fixed income portfolio investment managers to equitize cash, hedge certain exposures, and as substitutes for certain types of fixed income securities.

Rate of Return Assumption

The expected return on assets in our pension 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. We arrive at a 7 percent expected return on assets by considering both the historical and forecasted long-term rates of return on those asset classes. We expect a return of between 7 percent and 9 percent on return-seeking assets and between 3 percent and 5 percent for risk-mitigating assets. Certain trusts that hold assets for the SDG&E and Mobile Gas other postretirement benefit plans are subject to taxation, which impacts the expected after-tax return on assets in these plans.

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 SDG&E’s and SoCalGas’ Other Postretirement Benefit Plans

SDG&E’s and SoCalGas’ other postretirement benefit plans are funded by cash contributions from SDG&E and SoCalGas and their current retirees. The assets of these plans are placed into the pension master trust and other Voluntary Employee Beneficiary Association (VEBA) trusts. The assets in the VEBA trusts are invested at an allocation similar to the pension master trust, with 70 percent invested in return-seeking and 30 percent invested in risk-mitigating assets. This allocation is periodically reviewed to ensure that plan assets are best positioned to meet plan obligations.

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. Certain high yield fixed-income securities are valued by applying a price adjustment to the bid side to calculate a mean and ask value. Adjustments can vary based on maturity, credit standing, and reported trade frequencies. The bid to ask spread is determined by the investment manager based on the review of the available market information.

Registered Investment Companies – Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices for equity and certain fixed income securities or are 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 for the remaining fixed income securities.

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 on their review of the underlying investments as well as their utilization of discounted cash flows and other valuation models.

Venture Capital Funds – These funds consist of investments in private equities that are held by limited partnerships following various strategies, including venture capital and corporate finance. The partnerships generally have limited lives of 10 years, after which liquidating distributions will be received. Fair value is determined by attributing a proportionate share of net assets to an ownership interest in partners’ capital.

Real Estate Funds – Investments in real estate funds are valued based on the net asset value per share. Net asset value is based on the fair value of the underlying investments.

Derivative Financial Instruments – Forward currency contracts are valued at the prevailing forward exchange rate of the underlying currencies, and unrealized gain (loss) is recorded daily. Fixed income futures and options are marked to market daily. Equity index future contracts are valued at the last sales price quoted on the exchange on which they primarily trade.

The methods described are intended to produce a fair value calculation that is indicative of net realizable value or reflective of 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 and 10. 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.

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 the valuation techniques used in recurring fair value measurement.

The fair values of our pension plan assets by asset category are as follows:

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS
(Dollars in millions)
	Fair value at December 31, 2015
	Level 1		Level 2		Level 3		Total
SDG&E:
Equity securities:
Domestic(1)	$	269	$	―	$	―	$	269
Foreign		163		―		―		163
Domestic preferred		―		2		―		2
Foreign preferred		1		―		―		1
Registered investment companies		38		―		―		38
Fixed income securities:
U.S. Treasury securities		38		―		―		38
Domestic municipal bonds		―		9		―		9
Foreign government bonds		―		3		―		3
Domestic corporate bonds(2)		―		103		―		103
Foreign corporate bonds		―		30		―		30
Common/collective trusts(3)		―		94		―		94
Registered investment companies		―		2		―		2
Other investments(4)		―		―		1		1
Total investment assets(5)		509		243		1		753

SoCalGas:
Equity securities:
Domestic(1)		552		―		―		552
Foreign		334		―		―		334
Domestic preferred		―		4		―		4
Foreign preferred		2		1		―		3
Registered investment companies		77		―		―		77
Fixed income securities:
U.S. Treasury securities		76		―		―		76
Domestic municipal bonds		―		19		―		19
Foreign government bonds		―		6		―		6
Domestic corporate bonds(2)		―		209		―		209
Foreign corporate bonds		―		62		―		62
Common/collective trusts(3)		―		193		―		193
Registered investment companies		―		5		―		5
Other investments(4)		1		―		3		4
Total investment assets(6)		1,042		499		3		1,544

Other Sempra Energy:
Equity securities:
Domestic(1)		72		―		―		72
Foreign		43		―		―		43
Domestic preferred		―		1		―		1
Registered investment companies		9		―		―		9
Fixed income securities:
U.S. Treasury securities		10		―		―		10
Domestic municipal bonds		―		3		―		3
Foreign government bonds		―		1		―		1
Domestic corporate bonds(2)		―		26		―		26
Foreign corporate bonds		―		8		―		8
Common/collective trusts(3)		―		25		―		25
Total other Sempra Energy(7)		134		64		―		198
Total Sempra Energy Consolidated(8)	$	1,685	$	806	$	4	$	2,495

(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, stated at net asset value, and derivative financial instruments.
(5)	Excludes cash and cash equivalents of $4 million, accounts payable of $7 million and transfers receivable from other plans of $2 million at SDG&E.
(6)	Excludes cash and cash equivalents of $9 million and accounts payable of $16 million at SoCalGas.
(7)	Excludes cash and cash equivalents of $1 million, accounts payable of $2 million and transfers payable to other plans of $2 million at Other Sempra Energy.
(8)	Excludes cash and cash equivalents of $14 million and accounts payable of $25 million at Sempra Energy Consolidated.

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS
(Dollars in millions)
	Fair value at December 31, 2014
	Level 1		Level 2		Level 3		Total
SDG&E:
Equity securities:
Domestic(1)	$	307	$	―	$	―	$	307
Foreign		186		―		―		186
Domestic preferred		―		1		―		1
Foreign preferred		1		―		―		1
Registered investment companies		40		―		―		40
Fixed income securities:
U.S. Treasury securities		38		―		―		38
Domestic municipal bonds		―		11		―		11
Foreign government bonds		―		12		―		12
Domestic corporate bonds(2)		―		117		―		117
Foreign corporate bonds		―		36		―		36
Common/collective trusts(3)		―		62		―		62
Registered investment companies		―		10		―		10
Other investments(4)		―		―		4		4
Total investment assets(5)		572		249		4		825

SoCalGas:
Equity securities:
Domestic(1)		651		―		―		651
Foreign		395		―		―		395
Domestic preferred		―		3		―		3
Foreign preferred		3		1		―		4
Registered investment companies		86		―		―		86
Fixed income securities:
U.S. Treasury securities		80		―		―		80
Domestic municipal bonds		―		24		―		24
Foreign government bonds		―		25		―		25
Domestic corporate bonds(2)		―		249		―		249
Foreign corporate bonds		―		77		―		77
Common/collective trusts(3)		―		132		―		132
Registered investment companies		―		21		―		21
Other investments(4)		1		―		8		9
Total investment assets(6)		1,216		532		8		1,756

Other Sempra Energy:
Equity securities:
Domestic(1)		81		―		―		81
Foreign		49		―		―		49
Foreign preferred		―		1		―		1
Registered investment companies		10		―		―		10
Fixed income securities:
U.S. Treasury securities		9		―		―		9
Domestic municipal bonds		―		4		―		4
Foreign government bonds		―		3		―		3
Domestic corporate bonds(2)		―		30		―		30
Foreign corporate bonds		―		9		―		9
Common/collective trusts(3)		―		16		―		16
Registered investment companies		―		2		―		2
Other investments(4)		―		―		1		1
Total other Sempra Energy(7)		149		65		1		215
Total Sempra Energy Consolidated(8)	$	1,937	$	846	$	13	$	2,796

(1)	Investments in common stock of domestic corporations include, on a combined basis at SDG&E, SoCalGas and Other Sempra Energy, 11,558 shares of Sempra Energy common stock at a value of $1 million.
(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, stated at net asset value, and derivative financial instruments.
(5)	Excludes cash and cash equivalents of $3 million at SDG&E.
(6)	Excludes cash and cash equivalents of $7 million at SoCalGas.
(7)	Excludes cash and cash equivalents of $1 million at Other Sempra Energy.
(8)	Excludes cash and cash equivalents of $11 million at Sempra Energy Consolidated.

The fair values by asset category of the other postretirement benefit plan assets held in the pension master trust and in the additional trusts for SoCalGas’ other postretirement benefit plans and SDG&E’s other postretirement benefit plan (PBOP plan trusts) are as follows:

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
	Fair value at December 31, 2015
	Level 1		Level 2		Level 3		Total
SDG&E:
Equity securities:
Domestic(1)	$	39	$	―	$	―	$	39
Foreign		24		―		―		24
Registered investment companies		41		―		―		41
Fixed income securities:
U.S. Treasury securities		5		―		―		5
Domestic municipal bonds		―		3		―		3
Domestic corporate bonds(2)		―		15		―		15
Foreign corporate bonds		―		4		―		4
Common/collective trusts(3)		―		14		―		14
Registered investment companies		―		16		―		16
Total investment assets(4)		109		52		―		161

SoCalGas:
Equity securities:
Domestic(1)		123		―		―		123
Foreign		74		―		―		74
Domestic preferred		―		1		―		1
Registered investment companies		43		―		―		43
Broad market funds		―		216		―		216
Fixed income securities:
U.S. Treasury securities		42		―		―		42
Domestic municipal bonds		―		7		―		7
Domestic corporate bonds(2)		―		87		―		87
Foreign government bonds		―		2		―		2
Foreign corporate bonds		―		28		―		28
Common/collective trusts(3)		―		151		―		151
Registered investment companies		―		49		―		49
Total investment assets(5)		282		541		―		823

Other Sempra Energy:
Equity securities:
Domestic(1)		5		―		―		5
Foreign		3		―		―		3
Domestic preferred		―		1		―		1
Registered investment companies		4		―		―		4
Fixed income securities:
U.S. Treasury securities		2		―		―		2
Domestic corporate bonds(2)		―		1		―		1
Foreign government bonds		―		1		―		1
Foreign corporate bonds		―		1		―		1
Common/collective trusts(3)		―		1		―		1
Registered investment companies		―		1		―		1
Total other Sempra Energy		14		6		―		20
Total Sempra Energy Consolidated(6)	$	405	$	599	$	―	$	1,004

(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 and in the pension master trust.
(4)	Excludes cash and cash equivalents of $1 million and accounts payable of $1 million held in SDG&E PBOP plan trusts.
(5)	Excludes cash and cash equivalents of $3 million and accounts payable of $4 million held in SoCalGas PBOP plan trusts.
(6)	Excludes cash and cash equivalents of $4 million and accounts payable of $5 million at Sempra Energy Consolidated.

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
	Fair value at December 31, 2014
	Level 1		Level 2		Level 3		Total
SDG&E:
Equity securities:
Domestic(1)	$	41	$	―	$	―	$	41
Foreign		25		―		―		25
Registered investment companies		43		―		―		43
Fixed income securities:
U.S. Treasury securities		5		―		―		5
Domestic municipal bonds		―		3		―		3
Domestic corporate bonds(2)		―		16		―		16
Foreign government bonds		―		2		―		2
Foreign corporate bonds		―		5		―		5
Common/collective trusts(3)		―		8		―		8
Registered investment companies		―		16		―		16
Total investment assets		114		50		―		164

SoCalGas:
Equity securities:
Domestic(1)		133		―		―		133
Foreign		81		―		―		81
Domestic preferred		―		1		―		1
Foreign preferred		1		―		―		1
Registered investment companies		45		―		―		45
Broad market funds		―		222		―		222
Fixed income securities:
U.S. Treasury securities		16		―		―		16
Domestic municipal bonds		―		5		―		5
Domestic corporate bonds(2)		―		61		―		61
Foreign government bonds		―		5		―		5
Foreign corporate bonds		―		25		―		25
Common/collective trusts(3)		―		265		―		265
Registered investment companies		―		6		―		6
Other investments(4)		―		―		2		2
Total investment assets(5)		276		590		2		868

Other Sempra Energy:
Equity securities:
Domestic(1)		6		―		―		6
Foreign		3		―		―		3
Registered investment companies		4		―		―		4
Fixed income securities:
U.S. Treasury securities		1		―		―		1
Domestic corporate bonds(2)		―		2		―		2
Common/collective trusts(3)		―		1		―		1
Registered investment companies		―		2		―		2
Total other Sempra Energy(6)		14		5		―		19
Total Sempra Energy Consolidated(7)	$	404	$	645	$	2	$	1,051

(1)	Investments in common stock of domestic corporations include, on a combined basis at SDG&E, SoCalGas and Other Sempra Energy, 2,005 shares of Sempra Energy common stock at a value of $0.2 million.
(2)	Bonds of U.S. issuers from diverse industries, primarily investment-grade.
(3)	Investments in common/collective trusts held in PBOP plan VEBA trusts and in the pension master trust.
(4)	Investments in venture capital and real estate funds, stated at net asset value, and derivative financial instruments.
(5)	Excludes cash and cash equivalents of $2 million held in SoCalGas PBOP plan trusts.
(6)	Excludes cash and cash equivalents of $1 million held in Other Sempra Energy PBOP plan trusts.
(7)	Excludes cash and cash equivalents of $3 million at Sempra Energy Consolidated.

The investments of the pension master trust allocated to the pension and other 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:

LEVEL 3 INVESTMENT ASSETS
(Dollars in millions)
	Pension plans												Other postretirement benefit plans
	Level 3 investment assets						% of total investment assets						Level 3 investment assets						% of total investment assets
	2015			2014			2015			2014			2015			2014			2015			2014
SDG&E		$	1		$	4		―	%		―	%		$	―		$	―		―	%		―	%
SoCalGas			3			8		―			―				―			2		―			―
All other			―			1		―			―				―			―		―			―
Sempra Energy Consolidated		$	4		$	13		―			―			$	―		$	2		―			―

The following table provides a reconciliation of changes in the fair value of investments classified as Level 3:

LEVEL 3 RECONCILIATIONS
(Dollars in millions)
	SDG&E			SoCalGas			All other			Sempra Energy Consolidated
PENSION PLANS
Balance at January 1, 2014	$	6		$	13		$	2		$	21
Realized gains		1			2			―			3
Unrealized losses		(1	)		(2	)		―			(3	)
Sales		(2	)		(5	)		(1	)		(8	)
Balance at December 31, 2014		4			8			1			13
Realized gains		1			1			―			2
Unrealized gains		―			2			―			2
Sales		(4	)		(8	)		(1	)		(13	)
Balance at December 31, 2015	$	1		$	3		$	―		$	4
OTHER POSTRETIREMENT BENEFIT PLANS
Balance at January 1, 2014	$	1		$	2		$	―		$	3
Unrealized losses		(1	)		―			―			(1	)
Balance at December 31, 2014		―			2			―			2
Sales		―			(2	)		―			(2	)
Balance at December 31, 2015	$	―		$	―		$	―		$	―

Future Payments

We expect to contribute the following amounts to our pension and other postretirement benefit plans in 2016:

EXPECTED CONTRIBUTIONS
(Dollars in millions)
	Sempra Energy
	Consolidated			SDG&E			SoCalGas
Pension plans		$	126		$	5		$	77
Other postretirement benefit plans			5			2			1

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.

EXPECTED BENEFIT PAYMENTS
(Dollars in millions)
	Sempra Energy Consolidated						SDG&E						SoCalGas
				Other						Other						Other
	Pension			postretirement			Pension			postretirement			Pension			postretirement
	benefits			benefits			benefits			benefits			benefits			benefits
2016		$	325		$	47		$	86		$	8		$	187		$	36
2017			310			50			84			9			187			38
2018			311			53			82			10			186			40
2019			298			56			80			10			180			42
2020			291			61			77			10			175			44
2021-2025			1,295			296			339			54			808			228

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 $3 million for 2015, $4 million for 2014 and $4 million for 2013 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 2015, $10 million for 2014 and $9 million for 2013 related to this plan.

SAVINGS PLANS

Sempra Energy offers trusteed savings plans to all domestic employees and to employees in Mexico. 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, domestic employees may contribute from one percent to 50 percent of their eligible earnings, subject to annual IRS limits. In Mexico, employees may contribute up to 2 percent of the portion of their base salary that is less than 25 times the minimum wage and may contribute up to 5 percent of any portion of their base salary that is greater than 25 times the minimum wage.

Through March 27, 2015, Sempra Energy made matching contributions for all domestic employees after one year of the employee’s completed service. Beginning March 28, 2015, Sempra Energy makes matching contributions for domestic employees immediately as of the date of hire, except for represented employees at SoCalGas, who continue to receive matching contributions after one year of the employee’s completed service. Sempra Energy continues to make matching contributions immediately for employees in Mexico.

Also beginning March 28, 2015, employer contribution amounts for domestic employees, except for the represented employees at SoCalGas and employees at Mobile Gas, are equal to 50 percent of the first 6 percent, plus 20 percent of the next 5 percent, of eligible earnings contributed by employees. Prior to that, employer contribution amounts for these employees were 50 percent of the first 6 percent of eligible earnings contributed by the employees and, if certain company goals were met, an additional amount related to incentive compensation payments. Employer contribution amounts for represented employees at SoCalGas and employees at Mobile Gas remain generally equal to 50 percent of the first 6 percent of eligible earnings contributed by employees. Employees at Mobile Gas may also continue to receive an additional amount related to incentive compensation payments if certain company goals are met. Employer contributions for employees in Mexico remain equal to the contributions made by the employee.

Contributions to the savings plans were as follows:

CONTRIBUTIONS TO SAVINGS PLANS
(Dollars in millions)
	2015			2014			2013
Sempra Energy Consolidated		$	43		$	38		$	35
SDG&E			17			15			14
SoCalGas			21			18			17

The market value of Sempra Energy common stock held by the savings plans was $1.1 billion and $1.4 billion at December 31, 2015 and 2014, respectively.

NOTE 8. 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 employees, including those from the California Utilities, participate in Sempra Energy’s share-based compensation plans as a component of their compensation package.

In May 2013, shareholders approved the Sempra Energy 2013 Long-Term Incentive Plan. Upon approval, the remaining authorized shares from the Sempra Energy 2008 Long Term Incentive Plan and the 2008 Long Term Incentive Plan for EnergySouth, Inc. Employees and Other Eligible Individuals were applied to the number of shares authorized in the 2013 Plan.

At December 31, 2015, 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, in accordance with the terms of the grant, or upon eligibility for retirement. Options are subject to forfeiture or earlier expiration when an employee terminates employment.

Performance-Based Restricted Stock Units: These restricted stock unit awards generally vest in Sempra Energy common stock at the end of three-year (for awards granted in 2015) or four-year performance periods based on Sempra Energy’s total return to shareholders relative to that of specified market indices or based on the compound annual growth rate of Sempra Energy’s earnings per common share (EPS). For awards granted in 2013 or earlier, if Sempra Energy’s total return to shareholders exceeds target levels, up to an additional 50 percent of the number of granted restricted stock units may be issued. For awards granted during or after 2014, up to an additional 100 percent of the granted restricted stock units may be issued if total return to shareholders or EPS growth exceeds target levels. If Sempra Energy’s total return to shareholders or EPS growth is below the target levels but above threshold performance levels, shares are subject to partial vesting on a pro rata basis. For awards granted in 2015 that vest based on Sempra Energy’s total return to shareholders, a modifier adds 20 percent to the award’s payout (as initially calculated based on total return to shareholders relative to that of specified market indices) for total shareholder return performance in the top quartile relative to historical benchmark data for Sempra Energy and reduces the award’s payout by 20 percent for performance in the bottom quartile. However, in no event will more than an additional 100 percent of the granted restricted stock units be issued. If performance falls within the second or third quartiles, the modifier is not triggered, and the payout is based solely on total return to shareholders relative to that of specified market indices. Also, vesting may be subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control under the applicable long-term incentive plan, or in accordance with severance pay agreements. 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.

Other Performance-Based Restricted Stock Units: Restricted stock units were granted in 2014 and 2015 in connection with the creation of Cameron LNG JV. The 2014 awards vest to the extent that the Compensation Committee of Sempra Energy’s Board of Directors determines that the objectives of the joint venture are continuing to be achieved. These awards vest on the anniversary of the grant date over a period of either two or three years. The 2015 awards vest to the extent that the Compensation Committee of Sempra Energy’s Board of Directors determines that Sempra Energy has achieved positive cumulative net income for fiscal years 2015 through 2017 and Cameron LNG JV has commenced commercial operations of the first train. Vesting may be subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control under the applicable long-term incentive plan, or in accordance with severance pay agreements. 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.

Service-Based Restricted Stock Units: Restricted stock units may also be service-based; these generally vest at the end of three-year (for awards granted in 2015) or four-year service periods. Vesting may be subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control under the applicable long-term incentive plan, in accordance with severance pay agreements, or at the discretion of the Compensation Committee of Sempra Energy’s Board of Directors. 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: Restricted stock awards are solely service-based and 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 under the applicable long-term incentive plan, 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.

In April 2013, the IEnova board of directors approved the IEnova 2013 Long-Term Incentive Plan. The purpose of this plan is to align the interests of employees and directors of IEnova with its shareholders. All awards issued from this plan and any related dividend equivalents will settle in cash at vesting based on the price of IEnova common stock. In 2015, 2014 and 2013, IEnova issued 278,538; 468,339 and 1,014,899 restricted stock units from this plan, respectively, 570,218 of which remain outstanding at December 31, 2015. During 2015 and 2014, IEnova paid cash of $4 million and $3 million, respectively, to settle vested awards. No awards vested in 2013.

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 three or 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.

At December 31, 2015, 6,148,009 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,
	2015				2014				2013
Share-based compensation expense, before income taxes		$	48			$	46			$	38
Income tax benefit			(19	)			(18	)			(15	)
Share-based compensation expense, net of income taxes		$	29			$	28			$	23

Net share-based compensation expense, per common share
Basic		$	0.12			$	0.11			$	0.09
Diluted		$	0.12			$	0.11			$	0.09

Sempra Energy Consolidated’s capitalized share-based compensation cost was $6 million in 2015, $5 million in 2014 and $4 million in 2013.

We classify the tax benefits resulting from tax deductions in excess of tax benefits related to the compensation cost recognized for stock option exercises and the vesting of restricted stock and related dividend equivalents as financing cash flows. There was $52 million in realized tax benefits for share-based payment award deductions in 2015 over and above the $19 million income tax benefit shown above.

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 EXPENSE – SDG&E AND SOCALGAS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
SDG&E:
Compensation expense		$	8		$	8		$	8
Capitalized compensation cost			4			3			3
SoCalGas:
Compensation expense		$	10		$	8		$	8
Capitalized compensation cost			2			2			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 2015, 2014 or 2013.

The following table shows a summary of non-qualified stock options at December 31, 2015 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 January 1, 2015		757,412			$	53.84
Exercised		(227,815	)		$	54.48
Forfeited/canceled		(1,600	)		$	36.30
Outstanding at December 31, 2015		527,997			$	53.62		2.6		$	21

Vested at December 31, 2015		527,997			$	53.62		2.6		$	21
Exercisable at December 31, 2015		527,997			$	53.62		2.6		$	21

The aggregate intrinsic value at December 31, 2015 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

§	$12 million in 2015

§	$33 million in 2014

§	$41 million in 2013

All outstanding stock options were fully vested at December 31, 2014. The total fair value of shares vested in 2014 and 2013 was $1 million and $2 million, respectively.

We received cash of $12 million from option exercises during 2015.

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 historical 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 awards granted in 2015, 2014 and 2013 for Sempra Energy:

		2015		2014		2013
Risk-free rate of return		1.1	%	1.2	%	0.6	%
Annual dividend yield(1)		N/A		N/A		3.3
Stock price volatility		14		16		19
(1)	Annual dividend yield was not used in valuations performed in 2015 or 2014.

Restricted Stock Awards

We provide below a summary of Sempra Energy’s restricted stock awards at December 31, 2015 and the activity during the year.

RESTRICTED STOCK AWARDS

				Weighted-
				average
				grant-date
	Shares			fair value
Nonvested at January 1, 2015		9,238		$	63.81
Vested		(7,701	)	$	61.41
Nonvested at December 31, 2015		1,537		$	75.87
Expected to vest at December 31, 2015		1,537		$	75.87

Total compensation cost related to nonvested restricted stock awards not yet recognized as of December 31, 2015 is negligible. No restricted stock awards were granted in 2015 or 2014. The weighted-average per-share fair value for restricted stock awards granted in 2013 was $75.82.

The total fair value of shares vested in the last three years was $1 million in each of 2015, 2014 and 2013.

Restricted Stock Units

We provide below a summary of Sempra Energy’s restricted stock units as of December 31, 2015 and the activity during the year.

RESTRICTED STOCK UNITS

	Performance-based					Service-based
	restricted stock units(1)					restricted stock units
				Weighted-					Weighted-
				average					average
				grant-date					grant-date
	Units			fair value		Units			fair value
Nonvested at January 1, 2015		2,874,942		$	54.55		303,237			$	73.41
Granted		438,318		$	123.30		72,835			$	111.43
Vested		(1,036,645	)	$	42.34		(25,000	)		$	88.71
Forfeited		(4,940	)	$	103.58		(2,266	)		$	90.48
Nonvested at December 31, 2015(2)		2,271,675		$	73.28		348,806			$	80.14
Expected to vest at December 31, 2015		2,220,408		$	72.89		338,086			$	79.81

(1)

Includes restricted stock units issued in 2015 in connection with the creation of Cameron LNG JV.

(2)

Each unit represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For all performance-based restricted stock units, except for those issued in connection with the creation of Cameron LNG JV, up to an additional 50 percent (100 percent for awards granted during or after 2014) of the shares represented by the units may be issued if Sempra Energy exceeds target performance conditions.

The total fair value of shares vested was $46 million in 2015 and $33 million in each of 2014 and 2013.

The $39 million of total compensation cost related to nonvested restricted stock units not yet recognized as of December 31, 2015 is expected to be recognized over a weighted-average period of 1.9 years. The weighted-average per-share fair values for performance-based restricted stock units granted were $88.01 and $57.55 in 2014 and 2013, respectively. The weighted-average per-share fair values for service-based restricted stock units granted were $91.54 and $72.71 in 2014 and 2013, respectively.

NOTE 9. 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, benchmark interest rate risk and foreign exchange rate exposures. 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 included in the tables below.

In certain cases, we apply the normal purchase or sale exception to derivative instruments 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.

In all other cases, we record 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 (loss) (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.

HEDGE ACCOUNTING

We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency 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 the future cash flows of a given 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 instrument 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, as follows:

The California Utilities use energy derivatives, both natural gas and electricity, for the benefit of customers, with the objective of managing price risk and basis risks, and stabilizing and lowering natural gas and electricity costs. These derivatives include fixed price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments, or bilateral physical transactions. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas and electricity 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, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power 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: 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 at December 31, 2015 and 2014 as follows:

NET ENERGY DERIVATIVE VOLUMES

		December 31,
Segment and Commodity		2015		2014
California Utilities:
SDG&E:
	Natural gas	70 million MMBtu	(1)	55 million MMBtu
	Electricity	1 million MWh	(2)	―
	Congestion revenue rights	36 million MWh		27 million MWh
SoCalGas – natural gas		1 million MMBtu		1 million MMBtu

Energy-Related Businesses:
Sempra Natural Gas – natural gas		43 million MMBtu		29 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 contractual obligations and assets, 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, 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. Interest rate derivatives are generally accounted for as hedges, and 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 energy derivatives. Separately, Otay Mesa VIE has entered into interest rate swap agreements, designated as cash flow hedges, to moderate its exposure to interest rate changes.

At December 31, 2015 and 2014, the net notional amounts of our interest rate derivatives, excluding the cross-currency swaps discussed below, were:

INTEREST RATE DERIVATIVES
(Dollars in millions)
		December 31, 2015					December 31, 2014
		Notional debt			Maturities		Notional debt			Maturities
Sempra Energy Consolidated:
	Cash flow hedges(1)		$	384		2016-2028		$	399		2015-2028
	Fair value hedges			300		2016			300		2016
SDG&E:
	Cash flow hedge(1)			315		2016-2019			325		2015-2019
(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 at our Mexican subsidiaries, which have U.S. dollar denominated cash balances, 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. We utilize 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. We also utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and joint ventures.

In addition, Sempra South American Utilities uses foreign currency derivatives at its subsidiaries and joint ventures as a means to manage foreign currency rate risk. We discuss such swaps at Chilquinta Energía’s Eletrans joint venture investment in Note 4.

FINANCIAL STATEMENT PRESENTATION

Each Consolidated Balance Sheet reflects the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Consolidated Balance Sheets at December 31, 2015 and 2014, including the amount of cash collateral receivables that were not offset, as the cash collateral is in excess of liability positions.

DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31, 2015
										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(1)			Sundry			derivatives(2)			derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments(3)	$	4		$	1		$	(15	)	$	(156	)
Commodity contracts not subject to rate recovery		13			―			―			―
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery		245			32			(239	)		(21	)
Associated offsetting commodity contracts		(232	)		(20	)		232			20
Associated offsetting cash collateral		(6	)		―			4			―
Commodity contracts subject to rate recovery		28			49			(61	)		(64	)
Associated offsetting commodity contracts		(2	)		(2	)		2			2
Associated offsetting cash collateral		―			―			28			26
Net amounts presented on the balance sheet		50			60			(49	)		(193	)
Additional cash collateral for commodity contracts
not subject to rate recovery		2			―			―			―
Additional cash collateral for commodity contracts
subject to rate recovery		28			―			―			―
Total(4)	$	80		$	60		$	(49	)	$	(193	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)	$	―		$	―		$	(14	)	$	(23	)
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery		―			―			(1	)		―
Associated offsetting cash collateral		―			―			1			―
Commodity contracts subject to rate recovery		27			49			(60	)		(64	)
Associated offsetting commodity contracts		(2	)		(2	)		2			2
Associated offsetting cash collateral		―			―			28			26
Net amounts presented on the balance sheet		25			47			(44	)		(59	)
Additional cash collateral for commodity contracts
not subject to rate recovery		1			―			―			―
Additional cash collateral for commodity contracts
subject to rate recovery		27			―			―			―
Total(4)	$	53		$	47		$	(44	)	$	(59	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery	$	―		$	―		$	(1	)	$	―
Associated offsetting cash collateral		―			―			1			―
Commodity contracts subject to rate recovery		1			―			(1	)		―
Net amounts presented on the balance sheet		1			―			(1	)		―
Additional cash collateral for commodity contracts
subject to rate recovery		1			―			―			―
Total	$	2		$	―		$	(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.
(4)	Normal purchase contracts previously measured at fair value are excluded.

DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31, 2014
										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(1)			Sundry			derivatives(2)			derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments(3)	$	10		$	3		$	(17	)	$	(109	)
Commodity contracts not subject to rate recovery		25			―			―			―
Derivatives not designated as hedging instruments:
Interest rate instruments		8			27			(7	)		(22	)
Commodity contracts not subject to rate recovery		143			32			(135	)		(29	)
Associated offsetting commodity contracts		(129	)		(27	)		129			27
Associated offsetting cash collateral		(11	)		―			―			―
Commodity contracts subject to rate recovery		36			76			(36	)		(20	)
Associated offsetting commodity contracts		(3	)		(1	)		3			1
Associated offsetting cash collateral		―			―			23			13
Net amounts presented on the balance sheet		79			110			(40	)		(139	)
Additional cash collateral for commodity contracts
subject to rate recovery		14			―			―			―
Total(4)	$	93		$	110		$	(40	)	$	(139	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)	$	―		$	―		$	(16	)	$	(31	)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery		32			76			(32	)		(20	)
Associated offsetting commodity contracts		―			(1	)		―			1
Associated offsetting cash collateral		―			―			23			13
Net amounts presented on the balance sheet		32			75			(25	)		(37	)
Additional cash collateral for commodity contracts
subject to rate recovery		12			―			―			―
Total(4)	$	44		$	75		$	(25	)	$	(37	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	4		$	―		$	(4	)	$	―
Associated offsetting commodity contracts		(3	)		―			3			―
Net amounts presented on the balance sheet		1			―			(1	)		―
Additional cash collateral for commodity contracts
subject to rate recovery		2			―			―			―
Total	$	3		$	―		$	(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.
(4)	Normal purchase contracts previously measured at fair value are excluded.

The effects of derivative instruments designated as hedges on the Consolidated Statements of Operations and in Other Comprehensive Income (Loss) (OCI) and Accumulated Other Comprehensive Income (Loss) (AOCI) for the years ended December 31 were:

FAIR VALUE HEDGE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Years ended December 31,
	Location	2015				2014				2013
Sempra Energy Consolidated:
Interest rate instruments	Interest Expense		$	6			$	8			$	8
Interest rate instruments	Other Income, Net			(5	)			(3	)			(7	)
Total(1)			$	1			$	5			$	1

(1)

There was no hedge ineffectiveness in 2015 or 2013. There were gains of $9 million from hedge ineffectiveness in 2014. All other changes in the fair value of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and recorded in Other Income, Net.

CASH FLOW HEDGE IMPACTS
(Dollars in millions)
	Pretax (loss) gain										Pretax (loss) gain reclassified
	recognized in OCI										from AOCI into earnings
	(effective portion)										(effective portion)
	Years ended December 31,										Years ended December 31,
	2015			2014			2013			Location	2015			2014			2013
Sempra Energy Consolidated:
Interest rate and foreign
exchange instruments(1)	$	(18	)	$	(24	)	$	1		Interest Expense	$	(18	)	$	(21	)	$	(11	)
										Gain on Sale of Equity
Interest rate instruments		―			3			―		Interests and Assets		―			3			―
										Equity Earnings,
Interest rate instruments		(80	)		(127	)		15		Before Income Tax		(12	)		(10	)		(10	)
										Equity Earnings,
Interest rate instruments		(20	)		―			―		Net of Income Tax		(13	)		―			―
Commodity contracts not										Revenues: Energy-Related
subject to rate recovery		12			19			(4	)	Businesses		14			8			1
Total(2)	$	(106	)	$	(129	)	$	12			$	(29	)	$	(20	)	$	(20	)
SDG&E:
Interest rate instruments(1)(3)	$	(6	)	$	(9	)	$	8		Interest Expense	$	(12	)	$	(11	)	$	(9	)
SoCalGas:
Interest rate instrument(3)	$	―		$	―		$	―		Interest Expense	$	(1	)	$	(1	)	$	(1	)

(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.
(2)	There was $2 million, $1 million and $1 million of losses from ineffectiveness related to these cash flow hedges in 2015, 2014 and 2013, respectively.
(3)	There was negligible hedge ineffectiveness related to these cash flow hedges at SDG&E and SoCalGas in 2015, 2014 and 2013.

For Sempra Energy Consolidated, we expect that losses of $16 million, which are net of income tax benefit, that are currently recorded in AOCI (including $12 million in noncontrolling interests, substantially all of which is related to Otay Mesa VIE at SDG&E) 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.

SoCalGas expects that negligible losses, 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, 2015 is approximately 13 years and 3 years for Sempra Energy Consolidated and SDG&E, respectively. The maximum remaining term of hedged interest rate variability related to debt at equity method investees is 20 years.

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 IMPACTS
(Dollars in millions)
		Pretax (loss) gain on derivatives recognized in earnings
		Years ended December 31,
Location		2015			2014			2013
Sempra Energy Consolidated:
Interest rate and foreign
exchange instruments	Other Income, Net	$	(4	)	$	(24	)	$	17
Foreign exchange instruments	Equity Earnings,
	Net of Income Tax		(4	)		(5	)		(4	)
Commodity contracts not subject	Revenues: Energy-Related
to rate recovery	Businesses		42			17			(1	)
Commodity contracts not subject	Cost of Natural Gas, Electric
to rate recovery	Fuel and Purchased Power		―			3			―
Commodity contracts not subject
to rate recovery	Operation and Maintenance		(1	)		(4	)		1
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power		(126	)		(10	)		53
Commodity contracts subject
to rate recovery	Cost of Natural Gas		1			―			―
Total		$	(92	)	$	(23	)	$	66
SDG&E:
Commodity contracts not subject
to rate recovery	Operation and Maintenance	$	―		$	(1	)	$	―
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power		(126	)		(10	)		53
Total		$	(126	)	$	(11	)	$	53
SoCalGas:
Commodity contracts not subject
to rate recovery	Operation and Maintenance	$	(1	)	$	(2	)	$	1
Commodity contracts subject
to rate recovery	Cost of Natural Gas		1			―			―
Total		$	―		$	(2	)	$	1

CONTINGENT FEATURES

For Sempra Energy Consolidated and SDG&E, certain of our derivative instruments contain credit limits which vary depending on 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 Consolidated, the total fair value of this group of derivative instruments in a net liability position at December 31, 2015 and 2014 is $6 million and $9 million, respectively. At December 31, 2015, if the credit ratings of Sempra Energy were reduced below investment grade, $6 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, 2015 and 2014 is $5 million and $2 million, respectively. At December 31, 2015, 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 Consolidated, 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 10. 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 at December 31, 2015 and 2014. 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 presented in accordance with our netting policy, as we discuss in Note 9 under “Financial Statement Presentation.”

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 at December 31, 2015 and 2014 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).

For commodity contracts, interest rate derivatives and foreign exchange instruments, 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). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below under “Level 3 Information.”

§	Rabbi Trust 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). Investments in marketable securities at December 31, 2015 and 2014 were negligible.

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)
	Fair value at December 31, 2015
		Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Nuclear decommissioning trusts
Equity securities		$	619	$	―	$	―	$	―		$	619
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			47		44		―		―			91
Municipal bonds			―		156		―		―			156
Other securities			―		182		―		―			182
Total debt securities			47		382		―		―			429
Total nuclear decommissioning trusts(2)			666		382		―		―			1,048
Interest rate and foreign exchange instruments			―		5		―		―			5
Commodity contracts not subject to rate recovery			22		16		―		(4	)		34
Commodity contracts subject to rate recovery			―		1		72		28			101
Total		$	688	$	404	$	72	$	24		$	1,188

Liabilities:
Interest rate and foreign exchange instruments		$	―	$	171	$	―	$	―		$	171
Commodity contracts not subject to rate recovery			5		3		―		(4	)		4
Commodity contracts subject to rate recovery			―		68		53		(54	)		67
Total		$	5	$	242	$	53	$	(58	)	$	242

	Fair value at December 31, 2014
		Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Nuclear decommissioning trusts
Equity securities		$	655	$	―	$	―	$	―		$	655
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			62		47		―		―			109
Municipal bonds			―		129		―		―			129
Other securities			―		207		―		―			207
Total debt securities			62		383		―		―			445
Total nuclear decommissioning trusts(2)			717		383		―		―			1,100
Interest rate and foreign exchange instruments			―		48		―		―			48
Commodity contracts not subject to rate recovery			28		16		―		(11	)		33
Commodity contracts subject to rate recovery			―		1		107		14			122
Total		$	745	$	448	$	107	$	3		$	1,303

Liabilities:
Interest rate and foreign exchange instruments		$	―	$	155	$	―	$	―		$	155
Commodity contracts not subject to rate recovery			3		9		―		(4	)		8
Commodity contracts subject to rate recovery			―		52		―		(36	)		16
Total		$	3	$	216	$	―	$	(40	)	$	179

(1)	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(2)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
	Fair value at December 31, 2015
		Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Nuclear decommissioning trusts
Equity securities		$	619	$	―	$	―	$	―		$	619
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			47		44		―		―			91
Municipal bonds			―		156		―		―			156
Other securities			―		182		―		―			182
Total debt securities			47		382		―		―			429
Total nuclear decommissioning trusts(2)			666		382		―		―			1,048
Commodity contracts not subject to rate recovery			―		―		―		1			1
Commodity contracts subject to rate recovery			―		―		72		27			99
Total		$	666	$	382	$	72	$	28		$	1,148

Liabilities:
Interest rate instruments		$	―	$	37	$	―	$	―		$	37
Commodity contracts not subject to rate recovery			1		―		―		(1	)		―
Commodity contracts subject to rate recovery			―		67		53		(54	)		66
Total		$	1	$	104	$	53	$	(55	)	$	103

	Fair value at December 31, 2014
		Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Nuclear decommissioning trusts
Equity securities		$	655	$	―	$	―	$	―		$	655
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			62		47		―		―			109
Municipal bonds			―		129		―		―			129
Other securities			―		207		―		―			207
Total debt securities			62		383		―		―			445
Total nuclear decommissioning trusts(2)			717		383		―		―			1,100
Commodity contracts subject to rate recovery			―		―		107		12			119
Total		$	717	$	383	$	107	$	12		$	1,219

Liabilities:
Interest rate instruments		$	―	$	47	$	―	$	―		$	47
Commodity contracts not subject to rate recovery			1		―		―		(1	)		―
Commodity contracts subject to rate recovery			―		51		―		(36	)		15
Total		$	1	$	98	$	―	$	(37	)	$	62

(1)	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(2)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
	Fair value at December 31, 2015
		Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Commodity contracts subject to rate recovery		$	―	$	1	$	―	$	1		$	2
Total		$	―	$	1	$	―	$	1		$	2
Liabilities:
Commodity contracts not subject to rate recovery		$	1	$	―	$	―	$	(1	)	$	―
Commodity contracts subject to rate recovery			―		1		―		―			1
Total		$	1	$	1	$	―	$	(1	)	$	1

	Fair value at December 31, 2014
		Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Commodity contracts subject to rate recovery		$	―	$	1	$	―	$	2		$	3
Total		$	―	$	1	$	―	$	2		$	3
Liabilities:
Commodity contracts not subject to rate recovery		$	2	$	―	$	―	$	(2	)	$	―
Commodity contracts subject to rate recovery			―		1		―		―			1
Total		$	2	$	1	$	―	$	(2	)	$	1

(1)

Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

Level 3 Information

The following table sets forth reconciliations of changes in the fair value of congestion revenue rights (CRRs) and long-term, fixed-price electricity positions 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,
	2015				2014				2013
Balance at January 1		$	107			$	99			$	61
Realized and unrealized (losses) gains			(134	)			15				11
Allocated transmission instruments			12				19				51
Settlements			34				(26	)			(24	)
Balance at December 31		$	19			$	107			$	99
Change in unrealized (losses) gains relating to
instruments still held at December 31		$	(27	)		$	8			$	11

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 and long-term, fixed-price electricity positions on an ongoing basis. Inputs used to determine the fair value of CRRs and fixed-price electricity positions are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to these instruments to be recoverable through customer rates. As such, there is no impact to earnings 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. Annual auction prices are published once a year, typically in the middle of November, and remain in effect for the following year. The impact associated with discounting is negligible. Because auction prices are a less observable input, these instruments are classified as Level 3. The fair value of these instruments is derived from auction price differences between two locations. From January 1, 2015 to December 31, 2015, the auction prices ranged from $(16) per MWh to $8 per MWh at a given location, and from January 1, 2014 to December 31, 2014, the auction prices ranged from $(6) per MWh to $12 per MWh at a given location. 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 9.

Long-term, fixed-price electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs. At December 31, 2015, these inputs range from $21.45 per MWh to $60.05 per MWh. A significant increase or decrease in market electricity forward prices would result in a significantly higher or lower fair value, respectively.

Realized gains and losses associated with CRRs and long-term electricity positions, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power 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 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 at December 31, 2015 and 2014:

	December 31,
(Dollars in millions)	2015			2014
Sempra Energy Consolidated		$	30		$	14
SDG&E			28			12
SoCalGas			1			2

Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, temporary investments, accounts and notes receivable, current amounts due to/from unconsolidated affiliates, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. 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 that are not recorded at fair value on the Consolidated Balance Sheets at December 31:

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
	December 31, 2015
	Carrying			Fair Value
	amount			Level 1			Level 2			Level 3			Total
Sempra Energy Consolidated:
Noncurrent due from unconsolidated affiliates(1)		$	175		$	―		$	97		$	69		$	166
Total long-term debt(2)(3)			13,761			―			13,985			648			14,633
Preferred stock of subsidiary			20			―			23			―			23
SDG&E:
Total long-term debt(3)(4)		$	4,304		$	―		$	4,355		$	315		$	4,670
SoCalGas:
Total long-term debt(5)		$	2,513		$	―		$	2,621		$	―		$	2,621
Preferred stock			22			―			25			―			25

	December 31, 2014
	Carrying			Fair Value
	amount			Level 1			Level 2			Level 3			Total
Sempra Energy Consolidated:
Noncurrent due from unconsolidated affiliates(1)		$	184		$	―		$	132		$	38		$	170
Total long-term debt(2)(3)			12,347			―			12,782			917			13,699
Preferred stock of subsidiary			20			―			23			―			23
SDG&E:
Total long-term debt(3)(4)		$	4,461		$	―		$	4,563		$	425		$	4,988
SoCalGas:
Total long-term debt(5)		$	1,913		$	―		$	2,124		$	―		$	2,124
Preferred stock			22			―			25			―			25

(1)	Excluding accumulated interest outstanding of $11 million and $4 million at December 31, 2015 and 2014, respectively.
(2)	Before reductions for unamortized discount (net of premium) and debt issuance costs of $107 million and $102 million at December 31, 2015 and 2014, respectively, and excluding build-to-suit and capital leases of $387 million and $310 million at December 31, 2015 and 2014, respectively. We discuss our long-term debt in Note 5.
(3)	Level 3 instruments include $315 million and $325 million at December 31, 2015 and 2014, respectively, related to Otay Mesa VIE.
(4)	Before reductions for unamortized discount and debt issuance costs of $43 million and $47 million at December 31, 2015 and 2014, respectively, and excluding capital leases of $244 million and $234 million at December 31, 2015 and 2014, respectively.
(5)	Before reductions for unamortized discount and debt issuance costs of $24 million and $23 million at December 31, 2015 and 2014, respectively, and excluding capital leases of $1 million at both December 31, 2015 and 2014.

We base the fair value of certain noncurrent amounts due from unconsolidated affiliates, 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 noncurrent amounts due from unconsolidated affiliates of our South American Utilities using a perpetuity approach based on the obligation’s fixed interest rate, the absence of a stated maturity date and a discount rate reflecting local borrowing costs (Level 3). 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).

We provide the fair values for the securities held in the nuclear decommissioning trust funds related to SONGS in Note 13 below.

Non-Recurring Fair Value Measures – Sempra Energy Consolidated

Energía Sierra Juárez

In July 2014, Sempra Mexico completed the sale of a 50-percent interest in the 155-MW first phase of its Energía Sierra Juárez wind project to a wholly owned subsidiary of InterGen N.V. for cash proceeds of $24 million, net of $2 million cash sold, as discussed in Note 3. Sempra Mexico recognized a pretax gain on the sale of $19 million ($14 million after-tax). Upon deconsolidation, our equity method investment in Energía Sierra Juárez was measured at fair value, which resulted in a $7 million after-tax gain attributable to a remeasurement of the retained investment to fair value. The fair value measurement was based on the cash sales price of $26 million paid by InterGen N.V., a nonrelated party and market participant. Use of this market participant input as the indicator of fair value is a Level 2 measurement in the fair value hierarchy.

The following table summarizes significant inputs impacting non-recurring fair value measures related to our investment in Energía Sierra Juárez:

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED

(Dollars in millions)

Estimated

Fair

% of

Inputs used to

fair

value

Fair value

develop

Range of

value

Valuation technique

hierarchy

measurement

inputs

Investment in

Energía Sierra Juárez

)

Market approach

Level 2

100

Equity sale offer price

100

(1)

At measurement date of July 16, 2014. At December 31, 2015, our investment in Energía Sierra Juárez had a carrying value of $30 million, reflecting subsequent equity method activity to record distributions and earnings.

NOTE 11. PREFERRED STOCK

The table below shows the details of preferred stock for SoCalGas. All series of SDG&E preferred stock were redeemed during 2013 as we discuss below.

PREFERRED STOCK OUTSTANDING
(Dollars in millions, except per share amounts)
	December 31,
	2015				2014
$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 Pacific Enterprises			(2	)			(2	)
Sempra Energy - Total preferred stock of subsidiary		$	20			$	20

Following are the attributes of each company’s preferred stock. No shares currently outstanding are subject to mandatory redemption.

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 also 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 any new series of such stock would be established by the board of directors at the time of issuance.

SDG&E

In October 2013, SDG&E redeemed all six series of its outstanding shares of contingently redeemable preferred stock for $82 million, including a $3 million early call premium. Each series was redeemed for cash at redemption prices ranging from $20.25 to $26 per share plus accrued dividends up to the redemption date of $1 million. The early call premium is presented as Call Premium on Preferred Stock of Subsidiary on Sempra Energy’s and Call Premium on Preferred Stock on SDG&E’s Consolidated Statements of Operations. The shares are no longer outstanding.

SDG&E is currently authorized to issue up to 45 million shares of preferred stock. The rights, preferences, privileges and restrictions for any new series of preferred stock would be established by the board of directors at the time of issuance.

NOTE 12. SEMPRA ENERGY – SHAREHOLDERS’ EQUITY AND EARNINGS PER SHARE

The following table provides the per share computations for our earnings for years ended December 31, 2015, 2014 and 2013. Basic 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 AND DIVIDENDS DECLARED
(Dollars in millions, except per share amounts; shares in thousands)
	Years ended December 31,
	2015		2014		2013
Numerator:
Earnings/Income attributable to common shares	$	1,349	$	1,161	$	1,001

Denominator:
Weighted-average common shares outstanding for basic EPS(1)		248,249		245,891		243,863
Dilutive effect of stock options, restricted stock awards and
restricted stock units		2,674		4,764		5,469
Weighted-average common shares outstanding for diluted EPS		250,923		250,655		249,332

Earnings per share:
Basic	$	5.43	$	4.72	$	4.10
Diluted	$	5.37	$	4.63	$	4.01

Dividends declared per share of common stock	$	2.80	$	2.64	$	2.52

(1)

Includes fully vested restricted stock units held in our Deferred Compensation Plan of 491 in 2015, 212 in 2014 and none in 2013. These fully vested restricted stock units are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.

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, 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 of dilutive common stock equivalents 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). During 2015, 2014 and 2013, we had no such antidilutive stock options outstanding and no stock options outstanding that were antidilutive because of the unearned compensation and windfall tax benefits included in the assumed proceeds under the treasury stock method.

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, 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 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 no antidilutive RSAs from the application of unearned compensation in the treasury stock method during 2015, 2014 or 2013. There were 722; 4,087 and no such antidilutive RSUs during 2015, 2014 and 2013, respectively.

Our performance-based RSUs include awards that vest at the end of three-year (for awards granted in 2015) or four-year performance periods based on Sempra Energy’s total return to shareholders relative to that of specified market indices (Total Shareholder Return or TSR RSUs) or based on the compound annual growth rate of Sempra Energy’s EPS (EPS RSUs). The comparative market indices for the TSR RSUs are the Standard & Poor’s (S&P) 500 Utilities Index and the S&P 500 Index. We primarily use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies to develop our EPS RSU targets. TSR RSUs represent the right to receive from zero to 1.5 shares (2.0 shares for awards granted during or after 2014) of Sempra Energy common stock if performance targets are met. EPS RSUs represent the right to receive from zero to 2.0 shares of Sempra Energy common stock if performance targets are met. If performance falls between the targets specified for each performance metric, we calculate the payout using linear interpolation. Participants also receive additional shares for dividend equivalents on shares subject to RSUs, which are deemed reinvested to purchase additional units that become subject to the same vesting conditions as the RSUs to which the dividends relate.

Our RSAs, which are solely service-based, and those RSUs that are service-based or issued in connection with certain other performance goals represent the right to receive up to 1.0 share if the service requirements or certain other vesting conditions are met. These RSAs and RSUs have the same dividend equivalent rights as the performance-based RSUs described above. We include RSAs and these RSUs in potential dilutive shares at 100 percent, subject to the application of the treasury stock method. We include our TSR RSUs and EPS RSUs in potential dilutive shares at zero to up to 200 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 indices, dilutive TSR RSU shares may vary widely from period-to-period. If it were assumed that performance goals for all performance-based RSUs were met at maximum levels and if the treasury stock method were not applied to any of our RSAs or RSUs, the incremental potential dilutive shares would be 1,968,062; 949,351 and 641,751 for the years ended December 31, 2015, 2014 and 2013, 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.

Common stock activity consisted of the following:

COMMON STOCK ACTIVITY

		Years ended December 31,
			2015	2014	2013
Common shares outstanding, January 1			246,330,884	244,461,327	242,368,836
Restricted stock units vesting(1)			1,499,062	989,027	1,491,170
Stock options exercised			227,815	699,783	1,237,348
Savings plan issuance			652,631	398,042	―
Common stock investment plan(2)			249,665	205,203	―
Restricted stock issuances			―	―	21,121
Shares repurchased(3)			(661,977)	(422,498)	(657,148)
Common shares outstanding, December 31			248,298,080	246,330,884	244,461,327
(1)	Includes dividend equivalents.
(2)	Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares.
(3)	From time to time, we purchase shares of our common stock from long-term incentive plan participants who elect to sell to us a sufficient number of vested restricted shares or units to meet minimum statutory tax withholding requirements.

Our board of directors has the discretion to determine the payment and amount of future dividends.

NOTE 13. SAN ONOFRE NUCLEAR GENERATING STATION (SONGS)

SDG&E has a 20-percent ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which ceased operations in June 2013. On June 6, 2013, Southern California Edison Company (Edison), the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the Nuclear Regulatory Commission (NRC) to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC.

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 expenses 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 Steam Generator Replacement Project

As part of the Steam Generator Replacement Project (SGRP), the steam generators were replaced in SONGS Units 2 and 3, and the Units returned to service in 2010 and 2011, respectively. Both Units were shut down in early 2012 after a water leak occurred in the Unit 3 steam generator. Edison concluded that the leak was due to unexpected wear from tube-to-tube contact. At the time the leak was identified, Edison also inspected and tested Unit 2 and subsequently found unexpected tube wear in Unit 2’s steam generator. These issues with the steam generators ultimately resulted in Edison’s decision to permanently retire SONGS.

The replacement steam generators were designed and provided by Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc. (collectively MHI). In July 2013, SDG&E filed a lawsuit against MHI seeking to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators. In October 2013, Edison instituted arbitration proceedings against MHI seeking damages as well. SDG&E is participating in the arbitration as a claimant and respondent. We discuss these proceedings in Note 15.

Settlement Agreement to Resolve the CPUC’s Order Instituting Investigation (OII) into the SONGS Outage (SONGS OII)

SONGS OII

In November 2012, in response to the outage, the CPUC issued the SONGS OII, pursuant to California Public Utilities’ Code Section 455.5, which applies to cost recovery issues resulting from long-term outages of operating assets. The SONGS OII consolidated most SONGS outage-related issues into a single proceeding. The SONGS OII, among other things, designated all revenues associated with the investment in, and operation of, SONGS since January 1, 2012 as subject to refund to customers, pending the outcome of all phases of the proceeding. The SONGS OII proceeding was intended to determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of this outage, including purchased replacement power costs, which are typically recovered through the Energy Resource Recovery Account (ERRA).

Entry Into Settlement Agreement

Pursuant to CPUC rules concerning settlements, SDG&E, Edison, The Utility Reform Network (TURN), and the CPUC Office of Ratepayer Advocates (ORA) held a settlement conference in March 2014 to discuss the terms to resolve the SONGS OII, and in April 2014, SDG&E, along with Edison, TURN, the ORA and two other intervenors who joined the Settlement Agreement to the SONGS OII proceeding (collectively, the Settling Parties), filed a Settlement Agreement with the CPUC. On September 5, 2014, the CPUC issued a ruling proposing specific changes that included, as they relate to SDG&E, greater ratepayer benefit from third party cost recoveries and funding of a research program to reduce greenhouse gas emissions at a shareholder cost of $1 million per year for 5 years.

On September 23, 2014, the Settling Parties executed an Amended and Restated Settlement Agreement (Amended Settlement Agreement), which amended the Settlement Agreement to adopt all of the modifications and clarifications requested in the CPUC ruling. On October 9, 2014, the CPUC issued a proposed decision approving the Amended Settlement Agreement, which was adopted by the CPUC as a final decision on November 20, 2014.

As approved by the CPUC, the Amended Settlement Agreement constitutes a complete and final resolution of the SONGS OII and related CPUC proceedings regarding the SGRP at SONGS and the related outage and subsequent shutdown of SONGS. This resolution also required the compliance filing referenced below under “Accounting and Financial Impacts.” The Amended Settlement Agreement does not affect on-going or future proceedings before the NRC, or litigation or arbitration related to potential future recoveries from third parties (except for the allocation to ratepayers of any recoveries as described below) or proceedings addressing decommissioning activities and costs.

In November 2014, in accordance with the Amended Settlement Agreement, SDG&E filed an advice letter seeking authority from the CPUC, among other things, to implement the terms and establish the revenue requirement in accordance with the Amended Settlement Agreement in rates starting January 1, 2015. In December 2014, the CPUC approved the advice letter and authorized SDG&E to update rates accordingly, subject to revision pending the results of a CPUC review of the changes to the revenue requirement proposed by SDG&E for consistency with the terms of the approved settlement decision. In March 2015, SDG&E received a final disposition letter from the CPUC confirming that SDG&E’s proposed rate changes were in compliance with the approved settlement decision.

The following is a summary of the Amended Settlement Agreement as it relates to SDG&E.

Disallowances, Refunds and Rate Recoveries

The final decision provided that SDG&E:

§	remove from rate base, as of February 1, 2012, its investment in the SGRP and refund to its customers the amount collected for its investment in and any return on its investment in the SGRP since such date. As of February 1, 2012, SDG&E’s net book value in the SGRP was approximately $160 million;

§	be authorized to recover in rates its remaining investment in SONGS, including base plant and construction work in progress, generally over a ten-year period commencing February 1, 2012, together with a return on investment at a reduced rate equal to:

□	SDG&E’s weighted average return on debt, plus

□	50 percent of SDG&E’s weighted average return on preferred stock, as authorized in the CPUC’s Cost of Capital proceeding then in effect (collectively, SONGS rate of return or SONGS ROR).

This has resulted in a SONGS ROR of 2.35 percent for the period from January 1, 2013 through December 31, 2015. The SONGS ROR for future periods will fluctuate based on SDG&E’s authorized weighted average returns on debt and preferred stock in effect for those future periods. The 2.35 percent SONGS ROR will remain in effect through 2017;

§	be authorized to recover in rates its recorded 2012 and 2013 operations and maintenance expenses; in addition, SDG&E was authorized to recover in rates the recorded costs for the 2012 refueling outage of Unit 2, subject to customary prudency review;

§	be authorized to recover in rates, subject to a reasonableness review, its 2014 recorded operation and maintenance expenses and non-operating operations and maintenance expenses;

§	be authorized to recover in rates its remaining investment in materials and supplies over a ten-year period commencing February 1, 2012, together with a return on investment at the SONGS ROR;

§	be authorized to recover in rates its remaining investment in nuclear fuel inventory and any costs incurred, or to be incurred, associated with nuclear fuel supply contracts over a ten-year period, together with a return equal to SDG&E’s commercial paper borrowing rate;

be authorized to recover in rates through its fuel and purchased power balancing account (ERRA), subject to the normal CPUC compliance reviews, all costs incurred to purchase power in the market to replace the power that would have been generated at SONGS if not for the outage and shutdown of SONGS, and to recover by December 31, 2015 any SONGS-related ERRA undercollections, which amounts have been collected. SDG&E’s replacement power purchase costs through June 6, 2013 (the date of SONGS’ retirement) were approximately $165 million, using the methodology followed in the SONGS OII; and

have a five-year funding commitment of $1 million per year to the University of California Energy Institute (or other existing University of California entity engaged in energy technology development) to create a Research Development and Demonstration program, whose goal would be to deploy new technologies, methodologies, and /or design modifications to reduce GHG emissions, particularly at current and future generating plants in California. This term was a modification requested by the CPUC.

In April 2015, a petition for modification (PFM) was filed with the CPUC by Alliance for Nuclear Responsibility (A4NR), an intervenor in the SONGS OII proceeding, asking the CPUC to set aside its decision approving the Amended Settlement Agreement and reopen the SONGS OII proceeding. In June 2015, TURN, a party to the Amended Settlement Agreement, filed a response supporting the A4NR petition. TURN does not question the merits of the Amended Settlement Agreement, but is concerned that certain allegations regarding Edison raised by A4NR have undermined the public’s confidence in the regulatory process. SDG&E has responded that TURN’s concerns regarding public perception do not impact the reasonableness of the Amended Settlement Agreement and are insufficient to overturn it. SDG&E is unable to determine what actions the CPUC will take, if any, in response to the A4NR PFM.

In August 2015, ORA, also a party to the Amended Settlement Agreement, filed a PFM with the CPUC, withdrawing its support for the Amended Settlement Agreement and asking the CPUC to reopen the SONGS OII proceeding. The ORA does not question the merits of the Amended Settlement Agreement, but is concerned with the CPUC’s approach toward recent disclosures concerning Edison ex parte communications with the CPUC. SDG&E responded that the ORA’s PFM is insufficient to overturn the Amended Settlement Agreement, because the ORA fails to make a case that the Amended Settlement Agreement is no longer in the public interest. SDG&E is unable to determine what actions the CPUC will take, if any, in response to the ORA PFM.

Accounting and Financial Impacts

Through December 31, 2015, the cumulative after-tax loss from plant closure recorded by Sempra Energy and SDG&E is $125 million, including a reduction in the after-tax loss of $13 million recorded in the first quarter of 2015 based on the CPUC’s approval in March 2015 of SDG&E’s compliance filing and establishment of the SONGS settlement revenue requirement, and a reduction in the after-tax loss of $2 million based on a settlement with Nuclear Electric Insurance Limited in the fourth quarter of 2015, as we discuss below.

In the second quarter of 2013, based on an initial assessment of the financial impact of the outcome of the SONGS OII proceeding, SDG&E reported an after-tax loss from plant closure of $119 million. In the first quarter of 2014, after entering into the Settlement Agreement, SDG&E recorded a $9 million increase in the after-tax loss. In the fourth quarter of 2014, based on the compliance filing regarding SDG&E’s annual revenue requirement and the timing of refunds to ratepayers, SDG&E recorded a $12 million increase to the after-tax loss.

The regulatory asset for the expected recovery of SONGS costs, consistent with the Amended Settlement Agreement, is $257 million ($42 million current and $215 million long-term) at December 31, 2015 and is recorded on the Consolidated Balance Sheets in Other Current Assets and Regulatory Assets Noncurrent, respectively, at Sempra Energy, and in Regulatory Assets Current and Other Regulatory Assets Noncurrent, respectively, at SDG&E. The amortization period prescribed for the regulatory asset is 10 years, which began on February 1, 2012. However, since the CPUC’s final decision approving the Amended Settlement Agreement was not issued until November 2014, amortization did not commence until January 2015.

Settlement with Nuclear Electric Insurance Limited (NEIL)

As we discuss in Note 15, NEIL insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks. In October 2015, the SONGS co-owners (Edison, SDG&E and the City of Riverside) reached an agreement with NEIL to resolve all of SONGS’ insurance claims arising out of the failures of the replacement steam generators for a total payment by NEIL of $400 million, SDG&E’s share of which is $80 million. Pursuant to the terms of the SONGS OII Amended Settlement Agreement, after reimbursement of legal fees and a 5-percent allocation to shareholders, the net proceeds of $75 million were allocated to ratepayers through ERRA.

NRC Proceedings

In December 2013, Edison received a final NRC Inspection Report that identified a violation for the failure to verify the adequacy of the thermal-hydraulic and flow-induced vibration design of the Unit 3 replacement steam generator. In January 2014, Edison provided a response to the NRC Inspection Report stating that MHI, as contracted by Edison to prepare the SONGS replacement steam generator design, was the party responsible for validating the design of the steam generators.

In addition, the NRC issued an Inspection Report to MHI containing a Notice of Nonconformance for its flawed computer modeling in the design of the replacement steam generators.

Because SONGS has ceased operation, NRC inspection oversight of SONGS will now be continued through the NRC’s Decommissioning Power Reactor Inspection Program to verify that decommissioning activities are being conducted safely, that spent fuel is safely stored onsite or transferred to another licensed location, and that the site operations and licensee termination activities conform to applicable regulatory requirements, licensee commitments and management controls.

Nuclear Decommissioning and Funding

As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison has begun the decommissioning phase of the plant. The process of decommissioning a nuclear power plant is governed by the regulations of various governmental and other agencies, including but not limited to, those of the NRC, the U.S. Department of the Navy (the land owner) and the CPUC. The NRC regulations generally categorize the decommissioning activities into three phases: initial activities, major decommissioning and storage activities, and license termination. Initial activities include providing notice of permanent cessation of operations (provided by Edison to the NRC on June 12, 2013) and notice of permanent removal of fuel from the reactor vessels (provided by Edison on June 28 and July 22, 2013 for Units 3 and 2, respectively). Within two years after the cessation of operations, the licensee (Edison) must submit a post-shutdown decommissioning activities report (PSDAR), an irradiated fuel management plan (IFMP) and a site-specific decommissioning cost estimate (DCE). Edison submitted each of the PSDAR, the IFMP and the DCE to the NRC in September 2014.

In accordance with state and federal requirements and regulations, SDG&E has assets held in trusts, referred to as the Nuclear Decommissioning Trusts (NDT), to fund decommissioning costs for SONGS Units 1, 2 and 3. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work will be done when Units 2 and 3 are decommissioned. At December 31, 2015, the fair value of SDG&E’s NDT assets was $1.1 billion. Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. In February 2014, SDG&E filed a request with the CPUC for such authorization for costs incurred in 2013. In April 2015, SDG&E withdrew its pending request and filed a new request based on updated decommissioning cost information, seeking authorization to access trust funds for up to $55 million in decommissioning costs incurred in 2013. The CPUC authorized the request in July 2015. In August 2015, SDG&E withdrew $37 million of the authorized amount, $34 million of which will be funded to customers through the ERRA balancing account. Another $3 million of the amount withdrawn was used to refund regulatory assets and certain costs pursuant to the SONGS OII Settlement Agreement. The remaining $18 million of the CPUC authorization is expected to be withdrawn pending satisfactory clarification by the Internal Revenue Service (IRS) that certain spent fuel costs and other costs are eligible decommissioning costs, payable from qualified nuclear decommissioning trusts. We are uncertain as to when such clarification will be provided.

In October 2015, SDG&E filed a request with the CPUC seeking authorization to access trust funds for $36 million for SONGS Units 2 and 3 decommissioning costs incurred in 2014. The CPUC approved the request in November 2015. In December 2015, SDG&E withdrew $23 million of the authorized amount, $19 million of which will be funded to customers through the ERRA balancing account. Another $4 million of the amount withdrawn was used to refund regulatory assets and certain costs pursuant to the SONGS OII Settlement Agreement. The remaining $13 million will be withdrawn pending satisfactory clarification by the IRS, as discussed above.

SDG&E will continue to use working capital to pay for any SONGS Units 2 and 3 decommissioning costs incurred, and file periodic requests with the CPUC seeking authorization to access funds for reimbursement from the NDT for incurred decommissioning costs.

Nuclear Decommissioning Trusts

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 NDT. We provide additional fair value disclosures for the NDT in Note 10.

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
			Gross		Gross			Estimated
			unrealized		unrealized			fair
	Cost		gains		losses			value
At December 31, 2015:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies(1)	$	89	$	2	$	―		$	91
Municipal bonds(2)		148		8		―			156
Other securities(2)		194		1		(13	)		182
Total debt securities		431		11		(13	)		429
Equity securities		214		412		(7	)		619
Cash and cash equivalents		15		―		―			15
Total	$	660	$	423	$	(20	)	$	1,063
At December 31, 2014:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	$	103	$	6	$	―		$	109
Municipal bonds		121		8		―			129
Other securities		206		7		(6	)		207
Total debt securities		430		21		(6	)		445
Equity securities		215		444		(4	)		655
Cash and cash equivalents		30		1		―			31
Total	$	675	$	466	$	(10	)	$	1,131

(1)	Maturity dates are 2016-2065.
(2)	Maturity dates are 2016-2115.

The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales.

SALES OF SECURITIES
(Dollars in millions)
	Years ended December 31,
	2015				2014				2013
Proceeds from sales(1)		$	577			$	601			$	685
Gross realized gains			29				11				26
Gross realized losses			(15	)			(11	)			(18	)

(1)

Excludes securities that are held to maturity.

Net unrealized gains (losses) are included in Regulatory Liabilities Arising from Removal Obligations on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.

Ratepayer 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 ratepayer contributions.

Asset Retirement Obligation and Spent Nuclear Fuel

SDG&E’s asset retirement obligation related to decommissioning costs for the SONGS units was $667 million at December 31, 2015. 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 asset retirement obligation at December 31, 2015 is based on an updated cost study prepared in 2014 that reflects the acceleration of the start of decommissioning Units 2 and 3 as a result of the early closure of the plant. SDG&E’s share of decommissioning costs in 2014 dollars is approximately $937 million, or escalated to 2015 dollars, is $956 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 as Units 2 and 3 are decommissioned. The ISFSI will be decommissioned after a spent fuel storage facility becomes available and the U.S. Department of Energy (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 fully decommissioned. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS until the DOE accepts it for final disposal. Spent nuclear fuel for Units 2 and 3 has been stored in the SONGS spent fuel pools for each reactor and in the ISFSI.

We provide additional information about SONGS in Note 15.

NOTE 14. CALIFORNIA UTILITIES’ REGULATORY MATTERS

JOINT MATTERS

CPUC General Rate Case (GRC)

The CPUC uses a general rate case proceeding to set sufficient rates 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.

2016 General Rate Case (2016 GRC)

The California Utilities filed their 2016 General Rate Case (2016 GRC) applications in November 2014. These filings requested revenue requirement increases of $133 million and $256 million for SDG&E and SoCalGas, respectively, over their 2015 revenue requirements.

In September 2015, the California Utilities filed settlement agreements with the CPUC that resolve all material matters related to the proceeding, except for the revenue requirement implications of certain income tax benefits associated with flow-through repair allowance tax deductions, discussed below. The settlement agreements are with eight of eleven intervening parties. For SoCalGas, the settlement proposes a total revenue requirement in 2016 of $2.219 billion, which is $133 million less than its original request. The proposed settlement represents an increase of $122 million or 6 percent over the 2015 total revenue requirement, excluding the impact of the 2015 revenue requirement increase discussed below under “SoCalGas Matters – Increase to CPUC-Authorized Annual Revenue Requirement.” For SDG&E, the settlement proposes a total revenue requirement in 2016 of $1.811 billion, which is $100 million less than its original request (as revised). The proposed settlement represents an increase of $17 million, or one percent over the 2015 total revenue requirement. This increase reflects a $16 million adjustment to the 2015 estimated revenue requirement since the November 2014 filings. The filed settlement agreements also call for attrition adjustments of 3.5 percent for both 2017 and 2018. The California Utilities also filed a separate agreement, reached with ORA, proposing that a fourth year (2019) be added to the GRC period, with a revenue requirement increase of 4.3 percent over 2018. Because the 2016 settlement has not been finalized, the California Utilities will collect rates identical to 2015 authorized amounts until a 2016 decision is approved.

The settlement agreements described above exclude a proposal, for both SDG&E and SoCalGas, regarding certain intra-rate case income tax benefits. The proposal recommends that the CPUC adjust SoCalGas’ rate base by $92 million and SDG&E’s rate base by $93 million, and additionally reduce both utilities’ revenue requirements by amounts currently being tracked in tax memorandum accounts for the year 2015. At December 31, 2015, the pretax balances tracked in these memorandum accounts total $74 million for SoCalGas and $39 million for SDG&E. We believe the proposed treatment would violate and contradict long standing rate making and income tax policy, and would represent a material departure from historical practice. If this proposal is adopted, the outcome would reduce the revenue requirement amounts agreed to in the respective settlement agreements described above. SDG&E and SoCalGas do not expect that the prospective reduction to rate base described above would result in an immediate earnings impact if this proposal is adopted. However, if this proposal is adopted, the amounts currently being tracked in the tax memorandum accounts for 2015 could result in a material charge against earnings when the draft decision is received.

We anticipate all matters to be resolved in the CPUC’s final decision on the 2016 GRC proceeding. We expect the CPUC to issue a final decision in the proceeding in the second quarter of 2016.

2012 General Rate Case (Final 2012 GRC Decision)

In May 2013, the CPUC approved a final decision in the California Utilities’ 2012 GRC. The Final 2012 GRC Decision was effective retroactive to January 1, 2012, and SDG&E and SoCalGas recorded the cumulative earnings effect of the retroactive application of the Final 2012 GRC Decision of $69 million and $37 million, respectively, in the second quarter of 2013. For SDG&E and SoCalGas, respectively, these amounts included an incremental earnings impact of $52 million and $25 million related to 2012 and $17 million and $12 million related to the first quarter of 2013.

The amount of revenue associated with the retroactive period was recovered in SDG&E’s rates over a 28-month period beginning in September 2013, and in SoCalGas’ rates over a 31-month period beginning in June 2013. At December 31, 2014, SDG&E reported on its Consolidated Balance Sheet $162 million as a regulatory asset, all classified as current, representing the retroactive revenue from the Final 2012 GRC Decision recovered by SDG&E in rates in 2015. At December 31, 2014, SoCalGas reported on its Consolidated Balance Sheet a regulatory asset of $52 million, all classified as current, representing the retroactive revenue from the Final 2012 GRC Decision recovered in rates in 2015.

CPUC Cost of Capital

A CPUC 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), weighted on a basis consistent with the authorized capital structure. 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 CPUC-regulated electric distribution and generation as well as natural gas distribution, transmission and storage assets.

In addition, a cost of capital proceeding also addresses the automatic cost of capital adjustment mechanism (CCM) 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. The market-based benchmark for SDG&E’s and SoCalGas’ CCM is the 12-month average monthly A-rated utility bond index, as published by Moody’s for the 12-month period of October 1st through September 30th (CCM Period) of each calculation year. In the last cost of capital proceeding, SDG&E’s and SoCalGas’ CCM benchmark rate was set at 4.24 percent. If at the end of the CCM Period the monthly average benchmark rate falls outside of the established range of 3.24 percent to 5.24 percent, SDG&E’s and SoCalGas’ authorized ROE would be adjusted, upward or downward, by one-half of the difference between the 12-month average and the benchmark rate. In addition, the authorized recovery rate for SDG&E’s and SoCalGas’ cost of debt and preferred stock would be adjusted to their respective actual weighted average costs, with no change to the authorized capital structure. All three adjustments with the new rate would become effective on January 1st of the following year in which the benchmark range was exceeded. For the twelve-month period ended September 30, 2015, the 12-month average of monthly Moody’s A-rated utility bond index was 4.04 percent, which is within the established range of 3.24 percent and 5.24 percent.

The CCM only applies during the intervening years between scheduled cost of capital proceedings. In the year the cost of capital proceeding is scheduled, the cost of capital proceeding takes precedence over CCM and will set new rates for the following year.

In December 2014, the CPUC granted both SDG&E and SoCalGas an extension of their filing deadlines for their next cost of capital applications by one year, from April 2015 to April 2016. The CPUC also extended the current CCM until the April 2016 filing date. The one year extension was made in response to a joint request by SDG&E, SoCalGas, Pacific Gas and Electric Company (PG&E) and Edison with the CPUC in November 2014.

In November 2015, the CPUC granted both SDG&E and SoCalGas an extension of their filing deadlines for one more year to April 2017. This additional extension was made in response to a joint request with the CPUC by SDG&E, SoCalGas, PG&E and Edison. The CPUC also extended the current CCM until the April 2017 filing date. However, in the event the adjustment mechanism is triggered, the utilities agree that no changes to the current cost of capital will be made under the mechanism. In February 2016, the CPUC approved a joint PFM filed by the California Utilities, the ORA and TURN to effectuate the agreement among the parties.

SDG&E’s current CPUC-authorized ROR is 7.79 percent and SoCalGas’ current CPUC-authorized ROR is 8.02 percent based on their authorized capital structures as follows:

COST OF CAPITAL AND AUTHORIZED RATE STRUCTURE

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%

SDG&E files separately with the FERC for authorized ROE on FERC-regulated electric transmission operations and assets as described below in “Federal Energy Regulatory Commission (FERC) Formulaic Rate Matters”.

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 natural gas transmission pipelines located in populated areas that have not been pressure tested. The California Utilities filed their Pipeline Safety Enhancement Plan (PSEP) with the CPUC in August 2011. The California Utilities’ total estimated cost for Phase 1 of the two-phase plan is $2.1 billion ($1.6 billion for SoCalGas and $500 million for SDG&E) over the 10-year period of 2012 to 2022. We anticipate that these costs may be updated to reflect the development of more detailed estimates, actual costs experienced as portions of the work are completed and changes in scope. 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 were outside the scope of the 2012 GRC proceedings concluded in 2013. Similarly, these costs are not included in the California Utilities’ 2016 GRC filings.

In April 2012, the CPUC transferred the PSEP to the Triennial Cost Allocation Proceeding (TCAP) and authorized 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.

Also 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. The CPUC’s Safety and Enforcement Division 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 utilities’ pipeline safety plans filed pursuant to SB 705.

In June 2014, the CPUC issued a final decision in the TCAP proceeding addressing SDG&E’s and SoCalGas’ PSEP. Specifically, the decision determined the following for Phase 1 of the program:

§	approved the utilities’ model for implementing PSEP;

approved a process, including a reasonableness review, to determine the amount that the utilities will be authorized to recover from ratepayers for the interim costs incurred through the date of the final decision to implement PSEP, which is recorded in the regulatory accounts authorized by the CPUC as noted above;

§	approved balancing account treatment, subject to a reasonableness review, for incremental costs yet to be incurred to implement PSEP; and

§	established the criteria to determine the amounts that would not be eligible for cost recovery, including:

▢	certain costs incurred or to be incurred searching for pipeline test records,

▢	the cost of pressure testing pipelines installed after July 1, 1961 for which the company has not found sufficient records of testing, and

▢	any undepreciated balances for pipelines installed after 1961 that were replaced due to insufficient documentation of pressure testing.

As a result of this decision, SoCalGas recorded an after-tax earnings charge of $5 million in 2014 for costs incurred in prior periods that were no longer subject to recovery. After taking the amounts disallowed for recovery into consideration, as of December 31, 2015, SDG&E and SoCalGas have recorded PSEP costs of $10 million and $162 million, respectively, in the CPUC-authorized regulatory account. In regard to requesting recovery from customers for PSEP costs incurred and recorded in accordance with the TCAP decision, SDG&E and SoCalGas are authorized to file an application with the CPUC for recovery of such costs up to the date of the TCAP decision and then annually for costs incurred through the end of each calendar year beginning with the period ended December 31, 2015. SoCalGas and SDG&E currently expect to file such applications no later than the second quarter of the year following and would expect a decision from the CPUC approximately 12 to 18 months following the date of the application (i.e., a decision on the recovery of costs recorded in the PSEP regulatory accounts as of December 31, 2015 would be expected by mid-2017).

In October 2014, SDG&E and SoCalGas filed a petition for modification with the CPUC requesting authority to begin to recover PSEP costs from customers in the year in which the costs are incurred, subject to refund pending the results of a reasonableness review by the CPUC, instead of in a subsequent year. This request is pending at the CPUC.

In December 2014, SDG&E and SoCalGas filed an application with the CPUC for recovery of $0.1 million and $46 million, respectively, in costs recorded in the regulatory account through June 11, 2014. In June 2015, SDG&E and SoCalGas agreed to remove certain projects from the filing and defer their review to future proceedings and, as a result, are now requesting recovery of $0.1 million and $26.8 million, respectively. The ORA, TURN, and the Southern California Generation Coalition (SCGC) have recommended disallowances related to completed projects, as well as facilities build-out costs, de-scoped projects, and project management and consulting costs. The ORA’s recommended disallowance would result in an $11.1 million decrease to SoCalGas’ original recovery application of $26.8 million, to $15.7 million. The disallowance recommended by TURN and SCGC would result in a $2.3 million decrease to SoCalGas’ original recovery application of $26.8 million, to $24.5 million. We expect a decision on this application in the first half of 2016.

In July 2014, the ORA and TURN filed a joint application for rehearing of the CPUC’s June 2014 final decision. The ORA and TURN alleged that the CPUC made a legal error in directing that ratepayers, not shareholders, be responsible for the costs associated with testing or replacing transmission pipelines that were installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. In November 2014, the CPUC denied the ORA and TURN request for rehearing of the decision adopting the PSEP. In December 2014, the ORA and TURN sought rehearing of the CPUC’s decision on rehearing. In late December 2014, SoCalGas and SDG&E filed their opposition to this second application for rehearing, and are continuing to implement PSEP in accordance with the June 2014 CPUC decision. In March 2015, the CPUC issued a decision denying the ORA’s and TURN’s second request for rehearing, but keeping the record in the proceeding open to admit additional evidence on the limited issue of pressure testing of pipelines installed between January 1, 1956 and July 1, 1961. As part of this review, the CPUC will allow parties to submit additional evidence relevant to this narrow issue to ensure a complete record, with no additional discovery allowed. The ORA and TURN filed their responses on May 1, 2015. In December 2015, the CPUC issued a final decision finding that ratepayers should not bear the costs associated with pressure testing subject pipelines, or, if replaced, ratepayers should bear neither the average cost of pressure testing nor the undepreciated balance of abandoned pipelines. Through December 31, 2015, the after-tax disallowed costs for SoCalGas and SDG&E are $3.2 million and $0.5 million, respectively. In January 2016, SoCalGas and SDG&E jointly filed a request with the CPUC seeking rehearing of its December 2015 decision. A CPUC decision on the rehearing request is expected in 2016.

Utility Incentive Mechanisms

The CPUC applies performance-based measures and incentive mechanisms to all California investor-owned utilities (IOUs), 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. SDG&E has incentive mechanisms associated with:

§	operational incentives

§	energy efficiency

SoCalGas has incentive mechanisms associated with:

§	energy efficiency

§	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 probable that the CPUC would assess a penalty.

Energy Efficiency

The CPUC established incentive mechanisms that are based on the effectiveness of energy efficiency programs. In December 2013, the CPUC awarded $3.1 million to SoCalGas and $3.9 million to SDG&E for their 2011 program year results. In December 2014, the CPUC approved awards to SoCalGas and SDG&E of $5.9 million and $7.5 million, respectively, for program year 2012 and for the first half of program year 2013. In December 2015, the CPUC approved awards to SoCalGas and SDG&E of $4.2 million and $6.5 million, respectively, for the second half of program year 2013 and all of program year 2014.

In September 2015, the CPUC issued a decision granting two rehearing requests filed by the ORA and TURN regarding the utility incentive awards for SDG&E and SoCalGas, as well as Edison and PG&E, for program years 2006 through 2008, which totaled $16.2 million for SDG&E and $17.3 million for SoCalGas. The decision directs that the rehearing ensure that the incentive awards granted were just and reasonable and based on calculations verified by the CPUC, or otherwise refunded to customers. We expect a CPUC decision in the second half of 2016.

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 2015, 2014 and 2013, the CPUC approved GCIM awards for SoCalGas of $13.7 million, $5.8 million and $5.4 million, respectively, for the 12-month periods ending March 31, 2014, 2013 and 2012, respectively. In December 2015, the CPUC approved a $7.25 million GCIM award for SoCalGas for the 12-month period ended March 31, 2015.

Operational Incentives

The CPUC may establish operational incentives and associated performance benchmarks as part of a general rate case or cost of service proceeding. In the California Utilities’ Final 2012 GRC Decision, SDG&E was directed to establish a performance measure and incentive for electric reliability. In September 2014, the CPUC approved SDG&E’s proposed mechanism, which was applied to calendar year 2015 and will be considered in the 2016 GRC. The CPUC did not establish any operational incentives for SoCalGas in the Final 2012 GRC Decision.

SDG&E MATTERS

SONGS

We discuss regulatory and other matters related to SONGS in Note 13.

Power Procurement and Resource Planning

We discuss SDG&E’s major projects below in “California Utilities – Major Projects.”

Background – Electric Industry Regulation

California’s legislative response to the 2000 – 2001 energy crisis resulted in the California Department of Water Resources (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 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 power contracts expired in 2013, with one remaining transportation contract allocated to SDG&E that will expire in 2018.

Renewable Energy

SDG&E is subject to the Renewables Portfolio Standard (RPS) Program administered by both the CPUC and the California Energy Commission, 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 proceeding 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 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.

In August 2014, SDG&E made a required filing with the CPUC indicating that its procurement of renewable energy during the period January 1, 2011 through December 31, 2013 exceeded the 20-percent minimum amount required by RPS. 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 CPUC-imposed penalties, which could materially affect its business, cash flows, financial condition, results of operations and/or prospects. The limit on the total amount of penalties for failure to comply with the RPS requirements is $75 million for the first compliance period (2011-2013); $75 million for the second compliance period (2014-2016); $100 million for the third compliance period (2017-2020); and $25 million for each annual compliance period beginning in 2021.

SB 350, signed into law in October 2015, increased the RPS requirements to 50 percent by 2030, with interim targets of 40 percent by the end of 2024, and 45 percent by the end of 2027. SDG&E expects to be fully compliant with these RPS requirements. We expect the CPUC to begin implementation of SB 350 in 2016.

Sunrise Powerlink Electric Transmission Line

In August 2015, SDG&E filed a petition with the CPUC requesting that it revise and confirm the project cost cap for the Sunrise Powerlink, a 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. While post-energization construction activities for the project were completed in 2013, certain matters relating to outstanding claims were not resolved until the first quarter of 2015. The filing requests CPUC approval of the final expenditure report for the project and the proposed revisions to the total project cost cap. As evidenced in the final report, and summarized in the table below, actual expenditures for the project totaled $1,887.4 million (in 2012 dollars, on a net present value basis), which exceeds the total project cost cap approved by the CPUC in 2008 (CPUC Approval Decision) by $4.4 million.


SUNRISE POWERLINK ELECTRIC TRANSMISSION LINE – PROPOSED REVISIONS TO TOTAL PROJECT COST CAP
(Dollars in millions)
												Total
	Construction costs				Undergrounding on				Mitigation			(2012 dollars, net
	and AFUDC				Alpine Blvd.				and monitoring costs			present value basis)
Final status report		$	1,490.9			$	11.7			$	384.8		$	1,887.4
2008 CPUC approval decision			1,594.2				91.0				197.8			1,883.0
Difference		$	(103.3	)		$	(79.3	)		$	187.0		$	4.4

Subsequent to the required approvals of the U.S. Department of Interior, Bureau of Land Management in January 2009 and the U.S. Forest Service (USFS) in July 2010, which formed the basis of the CPUC Approval Decision summarized above, the CPUC’s Energy Division and the federal agencies published the Sunrise Final Mitigation Monitoring, Compliance, and Reporting Program (MMCRP). The MMCRP increased the amount of required mitigation activities and costs by $187 million. Offsetting this cost, in part, was a reduction in the total mileage of undergrounding on Alpine Boulevard by approximately two miles. The terms of the CPUC Approval Decision contemplate the potential reduction in undergrounding mileage at an estimated $11 million per one quarter mile. The CPUC Approval Decision did not anticipate the changes in monitoring and mitigation costs. In its petition, SDG&E proposes that the applicable total cost cap be revised and confirmed at the amount of $1,887.4 million. This amount will be the basis used in SDG&E’s FERC-regulated transmission rates. SDG&E expects a CPUC decision on the petition in 2016.

Federal Energy Regulatory Commission (FERC) Formulaic Rate Matters

In February 2013, SDG&E submitted its Electric Transmission Formula Rate (TO4) filing with the FERC to set the rate making methodology and rate of return for SDG&E’s FERC-regulated electric transmission operations and assets for a multi-year period beginning September 1, 2013. The TO4 filing proposed a FERC ROE of 11.3 percent and requested: 1) rates to be determined by a base period of historical costs and a forecast of capital investments and 2) a true-up period similar to balancing account treatment that is designed to provide SDG&E earnings of no more and no less than its actual cost of service including its authorized return on investment. In June and July 2013, the FERC issued orders accepting the filing, subject to refund, and established settlement and hearing procedures, with rates being effective September 1, 2013.

On January 31, 2014, SDG&E filed an uncontested multi-party settlement at the FERC regarding the TO4 filing. The settlement, approved by the FERC in May 2014, will be in effect through December 31, 2018, is subject to a one-time right of termination by any party, and established a 10.05 percent ROE. The settlement also requires SDG&E to make annual information filings on December 1 of a given year to update rates for the following calendar year. SDG&E also has the right to file for any ROE incentives that might apply under FERC rules. SDG&E’s debt to equity ratio will be set annually based on the actual ratio at the end of each year.

Energy Resource Recovery Account (ERRA)

The ERRA is the regulatory balancing account that SDG&E uses to recover the electric fuel and purchased power costs it incurs to provide energy to its bundled service customers. SDG&E files an application with the CPUC each year to establish the ERRA revenue requirement needed for the following calendar year. Additionally, to the extent the ERRA balance exceeds a certain tolerance or “ERRA Trigger”, SDG&E must file an application to adjust its rates upward or downward, as applicable, to address the under- or overcollected ERRA balance, respectively. In 2014, the CPUC authorized SDG&E to collect $221 million of revenue requirement as a result of an ERRA Trigger. SDG&E collected the revenue requirement over the period April 2014 through December 31, 2015. In December 2015, the CPUC approved SDG&E’s 2016 ERRA revenue requirement of $1.3 billion, an increase of $43 million from its 2015 revenue requirement. SDG&E implemented the increased revenue requirement, to be collected in 2016, beginning January 1.

Wildfire Claims Cost Recovery

In August 2009, SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC 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. In December 2012, the CPUC issued a final decision that ultimately did not approve the proposed 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.

In February 2014, the Presiding Judge assigned by the FERC to SDG&E’s annual Electric Transmission Formula Rate filing (TO3 Formula Cycle 6) issued an Initial Decision and an Order on Summary Judgment which authorizes SDG&E to recover all of the costs incurred and allocated to SDG&E’s FERC-regulated operations for the 12-month period ended March 31, 2012, resulting from settlement activities for 2007 wildfire claims. In connection with this proceeding, the CPUC filed an appeal in the Ninth Circuit Court of Appeal of an earlier decision by the FERC denying the CPUC’s request to postpone the FERC proceeding pending CPUC action on cost recovery of the excess wildfire costs. The FERC sought dismissal of the CPUC’s appeal on procedural grounds, and in December 2015, the Court of Appeal dismissed the appeal.

In September 2015, SDG&E filed an application with the CPUC requesting rate recovery of an estimated $379 million in costs related to the October 2007 wildfires that have been recorded to the Wildfire Expense Memorandum Account (WEMA). These costs represent a portion of the estimated total of $2.4 billion in costs and legal fees that SDG&E has incurred to resolve third-party damage claims arising from the October 2007 wildfires. The requested amount of $379 million is the net estimated cost incurred by SDG&E after deductions for insurance reimbursement ($1.1 billion), third party settlement recoveries ($824 million) and allocations to FERC-jurisdictional rates ($80 million), and reflects a voluntary 10 percent shareholder contribution applied to the net WEMA balance ($42 million). SDG&E requested a CPUC decision by the end of 2016 and is proposing to recover the costs in rates over a six- to ten-year period. Intervening parties have recommended a phased approach, with Phase 1 addressing the reasonableness of SDG&E’s actions leading up to the fires and a CPUC decision in the second half of 2017. Phase 2 would address the reasonableness of settlements entered into by SDG&E, with a CPUC decision in the second half of 2018.

We discuss the impact should SDG&E conclude that recovery in rates is no longer probable in “Legal Proceedings – SDG&E – 2007 Wildfire Litigation” in Note 15. We discuss how we assess the probability of recovery of our regulatory assets in Note 1.

SOCALGAS MATTERS

Aliso Canyon Natural Gas Storage Facility

We discuss various regulatory matters regarding the Aliso Canyon natural gas storage facility and leak in Note 15.

Increase to CPUC-Authorized Annual Revenue Requirement

In July 2011, SoCalGas updated its testimony in the 2012 GRC to reflect the impact of the extension of temporary bonus depreciation by the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Act). The 2010 Tax Act’s extension of bonus depreciation for U.S. federal income tax purposes for years 2010 through 2012 resulted in significant additional tax depreciation deductions. These additional deductions generated U.S. federal NOLs and the creation of an NOL-based deferred tax asset. The 2012 GRC decision denied recovery of any return associated with the NOL-based deferred tax asset unless an IRS Private Letter Ruling (PLR) was obtained, at which point SoCalGas would be authorized to file an advice letter seeking an increase to its revenue requirement.

In February 2015, the IRS issued a PLR that agreed with SoCalGas that the denial of any return on the NOL-based deferred tax asset was a violation of tax normalization rules. In March 2015, SoCalGas filed an advice letter to the CPUC providing the PLR and requesting an increase to its authorized GRC revenue requirement for 2012 through 2015. In April 2015, the CPUC approved the advice letter, and SoCalGas recorded the approved increases for 2012 through 2015, as follows:


APPROVED INCREASES TO THE 2012 GRC ANNUAL REVENUE REQUIREMENTS
(Dollars in millions)

		Pretax			After-tax
	2012(1)		$	6.4		$	3.8
	2013(1)			6.3			3.7
	2014(1)			6.4			3.8
	2015(2)			6.6			3.9
			$	25.7		$	15.2

(1)	The approved increase to after-tax earnings was recorded in the second quarter of 2015.
(2)	The approved increase to after-tax earnings for the first and second quarters of 2015 of $1.4 million and $0.8 million, respectively, was recorded in the second quarter of 2015. The approved increase to after-tax earnings for the third and fourth quarters of 2015 of $0.6 million and $1.1 million, respectively, was recorded in the respective quarters.

CALIFORNIA UTILITIES — MAJOR PROJECTS

MAJOR PROJECTS – JOINT UTILITIES

(Dollars in millions)

Project description

Estimated cost

Status

Southern Gas System Reliability Project

2013 application seeking authority to recover the full cost of the project.

800

850

In March 2015, CPUC issued a revised project scope and updated schedule.

Will enhance reliability on the southern portions of the California Utilities’ integrated natural gas transmission system (Southern System).

If approved, and subject to environmental permitting, the project could commence construction in 2017 and be in service by the end of 2019.

Also known as the North-South Gas Project.

Pipeline Safety & Reliability Project

September 2015 application seeking authority to recover the full cost of the project, involving construction of an approximately 47-mile, 36-inch natural gas transmission pipeline in San Diego County.

600

January 2016 ruling directing SDG&E and SoCalGas to file an amended application by March 21, 2016 and provide additional information and analysis regarding various project alternatives.

Will implement pipeline safety requirements and modernize the system; improve system reliability and resiliency by minimizing dependence on a single pipeline; and enhance operational flexibility to manage stress conditions by increasing system capacity.

After CPUC approval, and subject to timing of other approvals, will take approximately 24 to 36 months to construct.

MAJOR PROJECTS – SDG&E

(Dollars in millions)

Project description

Estimated cost

Status

Cleveland National Forest (CNF) Transmission Projects

2012 application for permit to construct various transmission line replacement projects in and around CNF.

400

450

Alternatives identified in July 2015 joint CPUC/USFS environmental impact report (EIR/EIS), if approved by CPUC and USFS, would result in an increase to the estimated cost of the projects.

To replace and fire-harden five existing transmission lines.

Separate USFS and CPUC decisions on the transmission projects expected in the first half of 2016.

Various phases expected to be placed in service starting in 2016 and continuing through 2019.

Sycamore-Peñasquitos Transmission Project

230-kV transmission project to provide 16.7-mile transmission connection between Sycamore Canyon and Peñasquitos substations.

120

150

In March 2014, California ISO selected SDG&E in a competitively bid process to construct the project, which we originally estimated to cost $120 million to $150 million.

California ISO and state task force identified as necessary to ensure grid reliability given the closure of SONGS.

September 2015 draft EIR/EIS recommends an alternative that undergrounds more of the project than originally proposed. The CPUC may consider this alternative, which has an estimated cost of $250 million to $300 million.

CPUC decision expected in the first half of 2016, with the line expected to be in service in mid-2017.

South Orange County Reliability Enhancement

2012 application for Certificate of Public Convenience and Necessity (CPCN) to enhance the capacity and reliability of electric service to the south Orange County area.

350

400

Final CPUC decision expected in the first half of 2016.

Replacing and upgrading approximately eight miles of transmission lines and rebuilding and upgrading a substation at an existing site.

Planned in phases; entire project expected to be in service in 2020.

South Bay Substation and Relocation Project

2010 application with the CPUC for permit to construct new Bay Boulevard substation to replace the aging and obsolete South Bay substation.

145

175

July 2014 petition filed with the CPUC requesting modifications to the prior CPUC decision to authorize additional construction activities required by the coastal development permit.

Demolish existing substation when the Bay Boulevard substation has been constructed, energized and all transmission lines have been transferred.

CPUC approved the petition for modification in January 2015. Project expected to be in service in 2017.

Electric Vehicle Charging Program

April 2014 proposal for program to build and own a total of 5,500 electric vehicle charging units at estimated cost of $103 million, of which $59 million is capital investment.

January 2016 CPUC final decision denies proposal but authorizes a 3-year, $45 million program providing up to 3,500 charging units.

Hourly Vehicle-to-Grid Integration rate to incent vehicle charging during times of the day that benefit the power grid.

Distribution Resource Plan

July 2015 application filed with the CPUC submitting Distribution Resource Plan. Distributed energy resources (DER) are typically smaller power sources connected to the distribution grid and located near load centers.

TBD

SDG&E expects the CPUC to address the Distribution Resource Plan in a phased manner with more than one decision issued in the 2016 to 2017 time period.

NOTE 15. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount 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, 2015, Sempra Energy’s accrued liabilities for legal proceedings, including associated legal fees and costs of litigation, on a consolidated basis, were $49 million. At December 31, 2015, accrued liabilities for legal proceedings for SDG&E and SoCalGas were $26 million and $21 million, respectively. See discussion below for matters related to the Aliso Canyon natural gas leak.

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.” A September 2008 staff report issued by the CPUC’s Consumer Protection and Safety Division, now known as the Safety and Enforcement Division, 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.

Numerous parties 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. They asserted 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. SDG&E has resolved almost all of these lawsuits. One case remains subject to a damages-only trial, where the value of any compensatory damages resulting from the fires will be determined. Two appeals are pending after judgment in the trial court. SDG&E does not expect additional plaintiffs to file lawsuits given the applicable statutes of limitation, but could receive additional settlement demands and damage estimates from the remaining plaintiff until the case is resolved. SDG&E establishes reserves for the wildfire litigation as information becomes available and amounts are estimable.

SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of the costs incurred to resolve wildfire claims in excess of its liability insurance coverage and the amounts recovered from third parties. Accordingly, at December 31, 2015, Sempra Energy and SDG&E have recorded assets of $362 million in Other Regulatory Assets (long-term) on their Consolidated Balance Sheets, including $359 million related to CPUC-regulated operations, which represents the amount substantially equal to the aggregate amount it has paid and 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. On September 25, 2015, SDG&E filed an application with the CPUC seeking authority to recover these costs, as we discuss in Note 14. 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 at December 31, 2015, the resulting after-tax charge against earnings would have been up to approximately $213 million. A failure to obtain substantial or full recovery of these costs from customers, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s results of operations and cash flows.

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.

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 as part of Multi-District Litigation (MDL) proceedings, 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. The MDL court has finished ruling on pre-trial matters, and SDG&E expects that it will return the case to the Southern District of California.

Lawsuit Against Mitsubishi Heavy Industries, Ltd.

On July 18, 2013, SDG&E filed a lawsuit in the Superior Court of California in the County of San Diego against Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc. (collectively MHI). The lawsuit seeks to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators MHI provided to the SONGS nuclear power plant. The lawsuit asserts a number of causes of action, including fraud, based on the representations MHI made about its qualifications and ability to design generators free from defects of the kind that resulted in the permanent shutdown of the plant and further seeks to set aside the contractual limitation of damages that MHI has asserted. On July 24, 2013, MHI removed the lawsuit to the United States District Court for the Southern District of California and on August 8, 2013, MHI moved to stay the proceeding pending resolution of the dispute resolution process involving MHI and Edison arising from their contract for the purchase and sale of the steam generators. On October 16, 2013, Edison initiated an arbitration proceeding against MHI seeking damages stemming from the failure of the replacement steam generators. In late December 2013, MHI answered and filed a counterclaim against Edison. On March 14, 2014, MHI’s motion to stay the United States District Court proceeding was granted with instructions that require the parties to allow SDG&E to participate in the ongoing Edison/MHI arbitration. As a result, SDG&E is now participating in the arbitration as a claimant and respondent. Arbitration hearings are scheduled to begin in early 2016. We expect a decision by the end of 2016.

Investment in Wind Farm

In 2011, the CPUC and FERC approved SDG&E’s estimated $285 million tax equity investment in a wind farm project and its purchase of renewable energy credits from that project. SDG&E’s contractual obligations to both invest in the Rim Rock wind farm and to purchase renewable energy credits from the wind farm under the power purchase agreement are subject to the satisfaction of certain conditions which, if not achieved, would allow SDG&E to terminate the power purchase agreement and not make the investment. In December 2013, SDG&E received a closing notice from the project developer indicating that all such conditions had been met. SDG&E responded to the closing notice asserting that the contractual conditions had not been satisfied. On December 19, 2013, SDG&E filed a complaint against the project developer in San Diego Superior Court, asking that the court determine that SDG&E is entitled to terminate both the investment contract and the power purchase agreement due to the project developer’s failure to satisfy certain conditions. The project developer filed a separate complaint against SDG&E in Montana state court asking that court to determine that SDG&E breached the investment contract and the power purchase agreement, and asking for several categories of relief, including requiring SDG&E to invest in the project, requiring SDG&E to continue performing under the power purchase agreement, and payment of damages.

On January 27, 2014, the Montana court ordered SDG&E to continue making payments under the power purchase agreement pending a hearing on the project developer’s preliminary injunction motion. On March 14, 2014, SDG&E notified the project developer that the investment agreement expired by its own terms because a closing had not occurred by that date. The project developer is disputing SDG&E’s position. On March 28, 2014, SDG&E filed an amended complaint against the project developer in San Diego seeking damages and declaratory relief that SDG&E was entitled to terminate the power purchase agreement and to permit the investment agreement to expire. On April 25, 2014, the Montana court granted the project developer’s preliminary injunction motion to prevent SDG&E from terminating the power purchase agreement on the grounds that the project developer would be irreparably harmed if the payments were not made while the parties’ respective rights were being determined in the litigation. The court did not rule on the merits of the parties’ claims. On July 18, 2014, the Montana Supreme Court determined that the parties’ contractual agreement to resolve any disputes in San Diego was mandatory, and ordered that the Montana action be dismissed. The San Diego court has scheduled a trial in May 2016. On February 11, 2016, SDG&E, the project developer and several of the project developer’s parent and affiliated entities entered into a conditional settlement agreement. Under the conditional settlement agreement, among other things, the parties agreed to terminate the tax equity investment arrangement, continue the power purchase agreement for the wind farm generation, and release all claims against each other. The conditional settlement agreement is not fully effective until approved by the CPUC.

Concluded Matter

In February 2011, opponents of the Sunrise Powerlink, a 500-kV electric transmission line between the Imperial Valley and the San Diego region that was energized and placed in service in June 2012, 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 appealed. On May 19, 2015 the California Court of Appeals affirmed the lower court’s decision and, on June 16, 2015, denied plaintiffs’ request for rehearing. Plaintiffs did not seek review by the California Supreme Court within the prescribed time, so the Court of Appeals decision is final.

SoCalGas

Aliso Canyon Natural Gas Storage Facility Gas Leak

Stopping the Leak and Mitigation Efforts. SoCalGas worked closely with several of the world’s leading experts to stop the leak, including planning and obtaining all necessary approvals for drilling relief wells. After discovering the leak, SoCalGas made seven unsuccessful attempts to plug SS25 by pumping fluids down the well shaft. In early December 2015, SoCalGas began drilling a relief well designed to stop the leak by plugging the well at its base. On February 11, 2016, SoCalGas began pumping heavy fluids through the relief well into SS25 near the base of the well, which controlled the flow of natural gas through the well and stopped the leak. In order to permanently seal the well and consistent with directives from the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR) and CPUC, SoCalGas then injected cement into SS25 at its base, and on February 18, 2016, the DOGGR confirmed that the well was permanently sealed.

SoCalGas has been providing temporary relocation support to residents in the nearby community who request it. In addition, SoCalGas has been providing air filtration and purification systems to those residents in the nearby community requesting them. On December 24, 2015, by stipulation and court order, SoCalGas agreed to implement a formal plan for assisting residents in the nearby community to temporarily relocate, as well as to pay for additional overtime and costs associated with extra Los Angeles Police Department security patrols, among other things. Pursuant to the order, SoCalGas also worked with representatives from the Los Angeles City Attorney’s office to establish a mediation process to resolve disputes between individuals requesting temporary relocation or other services under this plan and SoCalGas. As a result of receiving the confirmation from DOGGR that the SS25 well was permanently sealed, SoCalGas started winding down its temporary relocation support. Subject to certain exceptions, the period for temporary relocation support to residents who temporarily relocated to short-term housing, such as hotels, concluded on February 25, 2016. This deadline has been challenged and is subject to a recent court order extending such period for an additional 22 days for certain residents. SoCalGas has appealed this order extending the support period. Additionally, residents who have been placed in rental housing will have through the agreed term of their leases to return home. In addition, SoCalGas also intends to mitigate the GHG emissions from the actual natural gas released.

Governmental Investigations and Civil and Criminal Litigation. Various governmental agencies, including the DOGGR, Los Angeles County Department of Public Health (LA County DPH), South Coast Air Quality Management District (SCAQMD), California Air Resources Board (CARB), CPUC, U.S. Environmental Protection Agency, Los Angeles District Attorney’s Office and California Attorney General’s Office, are investigating this incident. On January 25, 2016, the DOGGR and CPUC selected Blade Energy Partners to conduct an independent analysis under their supervision and to be funded by SoCalGas to investigate the technical root cause of the Aliso Canyon leak. SoCalGas has been working in close cooperation with these agencies.

As of February 24, 2016, 83 lawsuits have been filed (81 in Los Angeles County Superior Court and 2 in San Diego County Superior Court) against SoCalGas, some of which have also named Sempra Energy, and, in derivative claims on behalf of Sempra Energy and SoCalGas, certain officers and directors of Sempra Energy and SoCalGas. These various lawsuits assert causes of action for negligence, strict liability, property damage, fraud, nuisance, trespass, and breach of fiduciary duties, among other things, and additional litigation may be filed against us in the future related to this incident. Many of these complaints seek class action status, compensatory and punitive damages, injunctive relief, and attorneys’ fees. The Los Angeles City Attorney and Los Angeles County Counsel have also filed a complaint on behalf of the people of the State of California against SoCalGas for public nuisance and violation of the California Unfair Competition Law. The California Attorney General, acting in her independent capacity and on behalf of the people of the State of California and the CARB, joined this lawsuit. The complaint, as amended to include the California Attorney General, adds allegations of violations of California Health and Safety Code sections 41700, prohibiting discharge of air contaminants that cause annoyance to the public, and 25510, requiring reporting of the release of hazardous material, as well as California Government Code section 12607 for equitable relief for the protection of natural resources. The complaint seeks an order for injunctive relief, to abate the public nuisance, and to impose civil penalties. The SCAQMD also filed a complaint against SoCalGas seeking civil penalties for alleged violations of several nuisance-related statutory provisions arising from the leak and delays in stopping the leak. That suit seeks up to $250,000 in civil penalties for each day the violations occurred.

All of these complaints are being reviewed by SoCalGas and outside legal counsel. The costs of defending against these civil and criminal lawsuits and cooperating with these investigations, and any damages and civil and criminal fines and other penalties, if awarded or imposed, could be significant and to the extent not covered by insurance, or if there were to be significant delays in receiving insurance recoveries, could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Governmental Orders, Additional Regulation and Reliability. On January 6, 2016, the Governor of the State of California issued the Governor’s Order proclaiming a state of emergency to exist in Los Angeles County due to the natural gas leak at the Aliso Canyon facility. The Governor’s Order implements the following orders, among other things:

Stopping the Leak: The Governor’s Order directs: subject to reliability restrictions, the CPUC and California Energy Commission to take all actions necessary to ensure that SoCalGas maximizes daily withdrawals of natural gas from the Aliso Canyon storage facility for use or storage elsewhere; the DOGGR to direct SoCalGas to take any and all viable and safe actions to capture leaking gas and odorants while relief wells are being completed; and the DOGGR to require SoCalGas to identify how it will stop the gas leak if relief wells fail to seal the leaking well, or if the existing leak worsens.

Protecting Public Health and Safety: State agencies will: continue the prohibition against SoCalGas injecting any gas into the Aliso Canyon storage facility until a comprehensive review, utilizing independent experts, of the safety of the storage wells and the air quality of the surrounding community is completed; expand real-time monitoring of emissions in the surrounding community; convene an independent panel of scientific and medical experts to review public health concerns stemming from the natural gas leak and evaluate whether additional measures are needed to protect public health; and take all actions necessary to ensure the continued reliability of natural gas and electricity supplies in the coming months during the moratorium on gas injections into the Aliso Canyon storage facility.

§	Ensuring Accountability: The CPUC will ensure that SoCalGas covers costs related to the natural gas leak and its response, while protecting ratepayers; and CARB will develop a program to fully mitigate the leak’s emissions of methane by March 31, 2016, with such program to be funded by SoCalGas.

Strengthening Oversight: The DOGGR will promulgate emergency regulations for gas storage facility operators throughout the state, requiring: at least daily inspection of gas storage well heads using gas leak detection technology such as infrared imaging; ongoing verification of the mechanical integrity of all gas storage wells; ongoing measurement of annular gas pressure or annular gas flow within wells; regular testing of all safety valves used in wells; minimum and maximum pressure limits for each gas storage facility in the state; and a comprehensive risk management plan for each facility that evaluates and prepares for risks, including corrosion potential of pipes and equipment. Additionally, the DOGGR, the CPUC, the CARB and the California Energy Commission will submit to the Governor’s Office a report that assesses the long-term viability of natural gas storage facilities in California.

As described above, SoCalGas is addressing a number of the actions required by the Governor’s Order, while at the same time continuing to reliably supply natural gas to its customers. In addition, SoCalGas continues to work in close cooperation with the Governor’s Office and the state agencies described in the Order.

During the month of January 2016, the Hearing Board of the SCAQMD conducted public hearings on a stipulated abatement order regarding the Aliso Canyon leak. On January 23, 2016, the Hearing Board ordered SoCalGas to, among other things: stop all injections of natural gas except as directed by the CPUC, withdraw the maximum amount of natural gas feasible in a contained and safe manner, subject to orders of the CPUC, and permanently seal the well once the leak has ceased; continuously monitor the well site with infrared cameras until 30 days after the leak has ceased; provide the public with daily air monitoring data collected by SoCalGas; provide the SCAQMD with certain natural gas injection, withdrawal and emissions data from the Aliso Canyon facility; prepare and submit to the SCAQMD for its approval an enhanced leak detection and reporting well inspection program for the Aliso Canyon facility; provide the SCAQMD with funding to develop a continuous air monitoring plan for the Aliso Canyon facility and the nearby schools and community; prepare and submit to the SCAQMD for its approval an air quality notification plan to provide notice to SCAQMD, other public agencies and the nearby community in the event of a future reportable release; and provide the SCAQMD with funding to conduct an independent health study on the potential impacts of exposure to the constituents of the natural gas released from the facility as well as any odor suppressants used to mitigate odors from the leaking well. Additional hearings in the state legislature as well as with various other regulatory agencies have been or are expected to be scheduled, additional legislation has been proposed in the state legislature, and additional laws, orders, rules and regulations may be adopted.

SoCalGas estimates that approximately 57 Bcf of natural gas has been delivered to customers or moved to other gas storage facilities from an initial starting point of approximately 77 Bcf of gas in storage on October 23, 2015 at the Aliso Canyon facility. The CPUC has directed SoCalGas to maintain a minimum of 15 Bcf of working natural gas to help ensure reliability of the system through the spring and summer months, and based upon the CARB estimates of lost gas, the facility is approximately at this level. As a result and consistent with the order issued by the Hearing Board of the SCAQMD as described above, SoCalGas is no longer withdrawing gas from this facility. SoCalGas will conduct a measurement of natural gas lost from the leak and will provide that information to the relevant regulatory bodies.

Natural gas withdrawn from storage is important for ensuring service reliability during peak demand periods, including heating needs in the winter, as well as peak electric generation needs in the summer. Aliso Canyon, with a storage capacity of 86 Bcf, is the largest storage facility and an important element of SoCalGas’ delivery system, serving millions of homes and businesses across Southern California. Aliso Canyon represents 63 percent of SoCalGas’ owned natural gas storage capacity. SoCalGas has not injected natural gas into Aliso Canyon since October 25, 2015, and in accordance with the Governor’s Order and subject to contrary CPUC reliability-based direction, SoCalGas will continue this moratorium on further injections until the completion of a review, utilizing independent experts, of the safety of each of the storage wells and air quality in the surrounding communities and an evaluation by an independent panel of scientific and medical experts on whether additional measures are needed to protect public health. We are also currently reviewing the recently released DOGGR safety review requirements associated with returning Aliso Canyon to an active injection/withdrawal status. In addition, effective February 5, 2016, the DOGGR amended the California Code of Regulations to require all underground natural gas storage facility operators, including SoCalGas, to take further steps to help ensure the safety of their gas storage operations. If this facility were to be taken out of service for any meaningful period of time, it could result in an impairment of the Aliso Canyon facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At December 31, 2015, the Aliso Canyon facility has a net book value of $243 million, excluding $162 million of construction work in progress for the project to construct a new compression station. Any significant impairment of this asset could have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations for the period in which it is recorded. Higher operating costs and additional capital expenditures incurred by SoCalGas may not be recoverable in customer rates, and SoCalGas’ and Sempra Energy’s results of operations, cash flows and financial condition may be materially adversely affected.

Cost Estimates and Accounting Impact. At December 31, 2015, SoCalGas recorded estimated costs of $330 million related to the leak. Of these amounts, approximately 70 percent is for the temporary relocation program and approximately 20 percent is for attempts to control the well, stop the leak, and stop or reduce the emissions. The remaining amount includes estimates for the value of lost gas, costs to mitigate the GHG emissions from the actual natural gas released, and other costs. The $330 million represents management’s best estimate of costs related to the leak. Of these costs, certain amounts have been paid and $274 million is recorded as Reserve for Aliso Canyon Costs at December 31, 2015 on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets for amounts expected to be paid in 2016. We will refine this estimate as further information becomes available, primarily from relocation companies who are administering the temporary relocation program. SoCalGas’ estimate of temporary relocation costs was primarily determined considering the current experience of temporary relocations. The remainder of the reserve was estimated primarily based on the rate of cost accumulation and duration of the leak. Any significant differences in actual costs incurred will impact these estimates. In addition, the period for temporary relocation support to residents who temporarily relocated to short-term housing, such as hotels, concluded on February 25, 2016. This deadline has been challenged and is subject to a recent court order extending such period for an additional 22 days for certain residents. SoCalGas has appealed this order extending the support period. Any increased costs related to such extension are not included in these estimates.

At December 31, 2015, we recorded the expected recovery of the costs described in the immediately preceding paragraph related to the leak (less insurance retentions) of $325 million as Insurance Receivable for Aliso Canyon Costs on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets. If we were to conclude that this receivable or a portion of it was no longer probable of recovery from insurers, some or all of this receivable may be charged against earnings.

The above amounts do not include any damage awards, any civil or criminal fines and other penalties that may be imposed, or associated legal costs, as it is not possible to predict the outcome of any criminal or civil proceeding or any administrative action in which such damage awards or civil or criminal fines or other penalties could be imposed, and any such amounts, if awarded or imposed, cannot be estimated at this time.

Insurance. We have at least four kinds of insurance policies that provide in excess of $1 billion in insurance coverage. We cannot predict all of the potential categories of costs or the total amount of costs that we may incur as a result of the leak. In reviewing each of our policies, and subject to various policy limits, exclusions and conditions, based upon what we know as of the filing date of this report, we believe that our insurance policies collectively should cover the following categories of costs: the costs incurred for temporary relocation, costs to address the leak and stop or reduce emissions, the value of lost natural gas and estimated costs to mitigate the GHG emissions from the actual natural gas released, the costs associated with litigation and claims by nearby residents and businesses, and, in some circumstances depending on their nature and manner of assessment, fines and penalties. We have been communicating with our insurance carriers and intend to pursue the full extent of our insurance coverage. There can be no assurance that we will be successful in obtaining insurance coverage for these costs under the applicable policies, and to the extent we are not successful, it could result in a material charge against earnings.

Other

SoCalGas, along with Monsanto Co., Solutia, Inc., Pharmacia Corp. and Pfizer, Inc., are defendants in seven 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 six of the seven lawsuits for an amount that is not significant.

Sempra Mexico

Permit Challenges and Property Disputes

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. Ownership of the adjacent property is not required by any of the environmental or other regulatory permits issued 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, and filed an action in the Federal Court challenging the permits. In February 2011, based on a complaint by the claimant, the municipality of Ensenada opened an administrative proceeding and sought 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. In the second quarter of 2014, the municipality of Ensenada dismissed the administrative proceeding. In the second quarter of 2015, the Administrative Court of Baja California confirmed the municipality of Ensenada’s ruling and dismissed the proceeding. 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 claimant also filed complaints in the federal Agrarian Court challenging the refusal of the Secretaría de la Reforma Agraria (now the Secretaría de Desarrollo Agrario, Territorial y Urbano, or SEDATU) in 2006 to issue a title to him for the disputed property. In November 2013, the Agrarian Court ordered that SEDATU issue the requested title and cause it to be registered. Both SEDATU and Sempra Mexico challenged the ruling, due to lack of notification of the underlying process. In November 2015, the Agrarian Court denied Sempra Mexico’s challenge, but the ruling does not affect any property rights. Another appeal filed by SEDATU is pending. Sempra Mexico expects additional proceedings regarding the claims, although such proceedings are not related to the permit challenges referenced above.

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. In September 2015, the Court granted Sempra Energy’s motion for summary judgment and closed the case. In October 2015, the claimant filed a notice of appeal of the summary judgment and an earlier order dismissing certain of his causes of action.

Additionally, several administrative challenges are pending in Mexico before the Mexican environmental protection agency (SEMARNAT) and 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. The Mexican Supreme Court decided to exercise jurisdiction over one such case, and in March 2014, issued a resolution denying the relief sought by the plaintiff on the grounds its action was not timely presented. A similar administrative challenge seeking to revoke the port concession for our marine operations at our Energía Costa Azul LNG terminal was filed with and rejected by the Mexican Communications and Transportation Ministry. In April 2015, the Federal court confirmed the Mexican Communications and Transportation Ministry’s ruling denying the request to revoke the port concession and decided in favor of Energía Costa Azul.

Two real property cases have been filed 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; one of these cases was dismissed in September 2013 at the direction of the state appellate court. A third complaint was served in April 2013 seeking to invalidate the contract by which Energía Costa Azul purchased another of the terminal parcels, on the grounds the purchase price was unfair. Sempra Mexico expects further proceedings on the remaining two matters.

Sempra Natural Gas

Since April 2012, a total of 14 lawsuits have been filed against Mobile Gas in Mobile County Circuit Court alleging that in the first half of 2008 Mobile Gas spilled tert-butyl mercaptan, an odorant added to natural gas for safety reasons, in Eight Mile, Alabama. Eleven of the lawsuits have been settled. The remaining three lawsuits, which include approximately 250 individual plaintiffs, allege nuisance, fraud and negligence causes of action, and seek unspecified compensatory and punitive damages.

Concluded Matter

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 alleged that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage. In August 2015, the parties settled this matter for an immaterial amount.

Other Litigation

Sempra Energy holds a noncontrolling interest in RBS Sempra Commodities LLP (RBS Sempra Commodities), a limited liability partnership in the process of being liquidated. The Royal Bank of Scotland plc (RBS), our partner in the joint venture, was notified by the United Kingdom’s Revenue and Customs Department (HMRC) that it was investigating value-added tax (VAT) refund claims made by various businesses in connection with the purchase and sale of carbon credit allowances. HMRC advised RBS that it had determined that it had grounds to deny such claims by RBS related to transactions by RBS Sempra Energy Europe (RBS SEE), a former indirect subsidiary of RBS Sempra Commodities that was sold to JP Morgan. HMRC asserted that RBS was not entitled to reduce its VAT liability by VAT paid during 2009 because RBS 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 a protective assessment of £86 million for the VAT paid in connection with these transactions. In October 2014, RBS filed a Notice of Appeal of the September 2012 assessment with the First-tier Tribunal. As a condition of the appeal, RBS was required to pay the assessed amount. The payment also stops the accrual of interest that could arise should it ultimately be determined that RBS has a liability for some of the tax. RBS has asserted that HMRC’s assessment was time-barred. A preliminary hearing is scheduled for September 19 to 21, 2016. In June 2015, liquidators for three companies that engaged in carbon credit trading via chains that included a company that RBS SEE traded with directly filed a claim in the High Court of Justice against RBS and RBS Sempra Commodities alleging that RBS Sempra Commodities’ and RBS SEE’s participation in transactions involving the sale and purchase of carbon credits resulted in the companies’ incurring VAT liability they were unable to pay. In October 2015, the liquidators’ counsel filed an amended claim adding seven additional trading companies to the claim and asserting damages of £156 million for all 10 companies. Additionally, the claimants dropped RBS Sempra Commodities LLP as a defendant, adding the successor to RBS SEE and JP Morgan, Mercuria Energy Europe Trading Limited (Mercuria), in its stead. JP Morgan has notified us that Mercuria has sought indemnity for the claim, and JP Morgan has in turn sought indemnity from us. Our remaining balance in RBS Sempra Commodities is accounted for under the equity method. The investment balance of $67 million at December 31, 2015 reflects remaining distributions expected to be received from the partnership as it is liquidated. The timing and amount of distributions may be impacted by these matters. We discuss RBS Sempra Commodities further in Note 4.

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 January 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 resolved all issues with regard to sales between the California Department of Water Resources 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.

We are also defendants in ordinary routine litigation incidental to our businesses, including personal injury, employment litigation, product liability, property damage and other claims. Juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.

CONTRACTUAL COMMITMENTS

Natural Gas Contracts

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 2031.

Sempra Natural Gas’ and Sempra Mexico’s businesses have various capacity agreements for natural gas storage and transportation. In addition, Sempra Mexico has a natural gas purchase agreement to fuel a natural gas-fired power plant.

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 contracted to third parties. Certain capacity release commitments have concluded, and contracting activity related to that capacity has not been sufficient to offset all of our capacity payments to Rockies Express. Sempra Natural Gas’ obligation to Rockies Express for future capacity payments is expected to exceed revenues generated from capacity released to others by $13 million in 2016, $14 million in 2017, $34 million in 2018, and $67 million in 2019.

At December 31, 2015, the future minimum payments under existing natural gas contracts and natural gas storage and transportation contracts were

FUTURE MINIMUM PAYMENTS – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Storage and
	transportation			Natural gas(1)			Total(1)
2016		$	258		$	100		$	358
2017			243			102			345
2018			217			85			302
2019			150			5			155
2020			46			5			51
Thereafter			186			13			199
Total minimum payments		$	1,100		$	310		$	1,410

(1)

Excludes amounts related to LNG purchase agreements discussed below.

FUTURE MINIMUM PAYMENTS – SOCALGAS
(Dollars in millions)
	Transportation		Natural gas		Total
2016	$	127	$	―	$	127
2017		114		1		115
2018		92		1		93
2019		48		1		49
2020		23		1		24
Thereafter		105		―		105
Total minimum payments	$	509	$	4	$	513

Total payments under natural gas contracts and natural gas storage and transportation contracts as well as payments to meet additional portfolio needs at Sempra Energy Consolidated and SoCalGas were:

PAYMENTS UNDER NATURAL GAS CONTRACTS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Sempra Energy Consolidated		$	1,200		$	1,984		$	1,680
SoCalGas			975			1,735			1,464

LNG Purchase Agreement

Sempra Natural Gas has a purchase agreement for the supply of LNG to the Energía Costa Azul terminal. The agreement is priced using a predetermined formula based on forward prices of the index applicable to each contract from 2016 to 2025 and an estimated one percent escalation per year beyond 2025 through contract termination in 2029. Although this contract specifies a number of cargoes to be delivered, under its terms, the customer may divert certain cargoes, which would reduce amounts paid under the contracts by Sempra Natural Gas. At December 31, 2015, the following LNG commitment amounts are based on the assumption that all cargoes, less those already confirmed to be diverted, under the contract are delivered:

LNG COMMITMENT AMOUNTS
(Dollars in millions)
2016	$	330
2017		432
2018		456
2019		487
2020		534
Thereafter		5,524
Total	$	7,763

Actual LNG purchases in 2015, 2014 and 2013 have been significantly lower than the maximum amount required under the agreement due to the customer electing to divert most cargoes as allowed by the agreement.

Purchased-Power Contracts

For 2016, SDG&E expects to meet its customer power requirements from the following resource types:

§	Long-term contracts: 38 percent (of which 33 percent is provided by renewable energy contracts expiring on various dates through 2041)

§	Other SDG&E-owned generation and tolling contracts (including OMEC): 56 percent

§	Spot market purchases: 6 percent

Chilquinta Energía and Luz del Sur also have purchased-power contracts, expiring on various dates extending through 2031, 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, 2015, the estimated future minimum payments under long-term purchased-power contracts were:

FUTURE MINIMUM PAYMENTS – PURCHASED-POWER CONTRACTS
(Dollars in millions)
	Sempra
	Energy
	Consolidated			SDG&E
2016		$	741		$	521
2017			726			504
2018			781			502
2019			776			493
2020			720			430
Thereafter			7,169			6,071
Total minimum payments(1)		$	10,913		$	8,521

(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, Chilquinta Energía and Luz del Sur are required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. Excluding DWR-allocated contracts at SDG&E, total payments under purchased-power contracts were:

PAYMENTS UNDER PURCHASED-POWER CONTRACTS
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Sempra Energy Consolidated		$	1,573		$	1,574		$	1,377
SDG&E(1)			715			710			570

(1)

Excludes DWR-allocated contracts. Under an operating agreement with the DWR that expired at the end of 2013, SDG&E acted 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 commodity costs associated with these contracts are not included in SDG&E's or Sempra Energy's Consolidated Statements of Operations.

Operating Leases

Sempra Energy Consolidated, SDG&E and SoCalGas have operating leases on real and personal property expiring at various dates from 2016 through 2054. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from two percent to five percent at Sempra Energy Consolidated, SDG&E and 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 an aggregate maximum lease limit of $150 million, $111 million of which has been utilized as of December 31, 2015.

Rent expense for operating leases is as follows:

RENT EXPENSE – OPERATING LEASES
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Sempra Energy Consolidated		$	78		$	78		$	81
SDG&E			27			26			23
SoCalGas			39			38			31

At December 31, 2015, the minimum rental commitments payable in future years under all noncancelable operating leases were as follows:

FUTURE MINIMUM PAYMENTS – OPERATING LEASES
(Dollars in millions)
	Sempra
	Energy
	Consolidated			SDG&E			SoCalGas
2016		$	71		$	25		$	38
2017			71			25			39
2018			63			19			36
2019			57			18			33
2020			50			16			28
Thereafter			283			70			131
Total future minimum rental commitments		$	595		$	173		$	305

Capital Leases

Power Purchase Agreements

SDG&E has four power purchase agreements with peaker plant facilities, one of which went into commercial operation in 2015. All four are accounted for as capital leases. At December 31, 2015, capital lease obligations for these leases, three with a 25-year term and one with a 9-year term, were valued at $243 million.

In the first quarter of 2015, SDG&E entered into a CPUC-approved 25-year power purchase agreement with a peaker plant facility that is currently under construction. Beginning with the initial delivery of the contracted power, scheduled in June 2017, the power purchase agreement will be accounted for as a capital lease.

The entities that own the peaker plant facilities are VIEs of which SDG&E is not the primary beneficiary. SDG&E does not have any additional implicit or explicit financial responsibility related to these VIEs.

At December 31, 2015, 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:

FUTURE MINIMUM PAYMENTS – POWER PURCHASE AGREEMENTS
(Dollars in millions)
2016				$	39
2017					77
2018					104
2019					104
2020					104
Thereafter					1,910
Total minimum lease payments(1)					2,338
Less: estimated executory costs					(523	)
Less: interest(2)					(1,072	)
Present value of net minimum lease payments(3)				$	743
	(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, which are recovered in rates.
	(2	)	Amount necessary to reduce net minimum lease payments to present value at the inception of the leases.
	(3	)	Includes $4 million in Current Portion of Long-Term Debt and $239 million in Long-Term Debt on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets at December 31, 2015. Of the present value of net minimum lease payments, $500 million will be recorded as a capital lease obligation when construction of the peaker plant facility is completed and delivery of contracted power commences, which is scheduled to occur in June 2017.

The annual amortization charge for the power purchase agreements was $4 million in 2015, $3 million in 2014 and $2 million in 2013.

Headquarters Build-to-Suit Lease

Sempra Energy has a 25-year, build-to-suit lease for its new San Diego, California, headquarters. We began occupying the building in the second half of 2015, concurrent with the termination of the prior headquarters lease. As a result of our involvement during and after the construction period, we have recorded the related assets and financing liability for construction costs incurred under this build-to-suit leasing arrangement.

The building is being depreciated on a straight-line basis over its estimated useful life and the associated lease payments are allocated between interest expense and amortization of the financing obligation over the lease period. Further, a portion of the lease payments pertain to the lease of the underlying land and are recorded as rental expense. The balance of the financing obligation, representing the net present value of the future minimum lease payments on the building, is $136 million at December 31, 2015.

At December 31, 2015, the future minimum lease payments on the lease are as follows:

FUTURE MINIMUM PAYMENTS – BUILD-TO-SUIT LEASE
(Dollars in millions)
2016	$	10
2017		10
2018		10
2019		10
2020		11
Thereafter		256
Total minimum lease payments	$	307

Other Capital Leases

The California Utilities entered into agreements in 2009 and 2010 to refinance existing fleet vehicles. These capital leases concluded during 2015.

The California Utilities entered into new capital leases during 2015 for additional fleet vehicles. At December 31, 2015, the related capital lease obligations were $1 million each at SDG&E and SoCalGas, payable in 2016.

Sempra South American Utilities entered into new capital leases for fleet vehicles and other assets during 2015. At December 31, 2015, capital lease obligations for these leases were $6 million.

At December 31, 2015, the future minimum lease payments under these capital leases for Sempra Energy Consolidated were $4 million in 2016, $2 million in 2017, $1 million in 2018, none in 2019 and 2020 and $8 million thereafter. The net present value of the minimum lease payments is $8 million at December 31, 2015.

The annual depreciation charge for the fleet vehicles and other assets during 2015, 2014 and 2013 was $4 million, $4 million and $7 million, respectively, at Sempra Energy Consolidated, including $2 million, $2 million and $4 million, respectively, at SDG&E and $2 million, $2 million and $3 million, respectively, at SoCalGas.

Construction and Development Projects

Sempra Energy Consolidated has various capital projects in progress in the United States, Mexico and South America. Sempra Energy’s total commitments under these projects are approximately $1.3 billion, requiring future payments of $1.2 billion in 2016, $53 million in 2017, $12 million in 2018, $17 million in 2019, $5 million in 2020 and $10 million thereafter. The following is a summary by segment of contractual commitments and contingencies related to such projects.

SDG&E

At December 31, 2015, SDG&E has commitments to make future payments of $157 million for construction projects that include

§	$61 million for the engineering, material procurement and construction costs primarily associated with the San Luis Rey Synchronous Condenser and Bay Boulevard Substation relocation projects;

§	$18 million related to nuclear fuel fabrication and other construction projects at SONGS; and

§	$78 million for infrastructure improvements for natural gas and electric transmission and distribution operations.

SDG&E expects future payments under these contractual commitments to be $67 million in 2016, $46 million in 2017, $12 million in 2018, $17 million in 2019, $5 million in 2020 and $10 million thereafter.

SoCalGas

At December 31, 2015, SoCalGas has commitments to make future payments of $18 million for construction and infrastructure improvements for transmission and distribution operations. The future payments under these contractual commitments are expected to be $11 million in 2016 and $7 million in 2017.

Sempra Mexico

At December 31, 2015, Sempra Mexico has commitments to make future payments of $264 million for contracts related to the construction of various natural gas pipeline projects. The future payments under these contractual commitments are all expected to be made in 2016.

Sempra Renewables

At December 31, 2015, Sempra Renewables has commitments to make future payments of $754 million for contracts related to the construction of renewable energy projects. The future payments under these contractual commitments are all expected to be made in 2016.

Sempra Natural Gas

At December 31, 2015, Sempra Natural Gas has commitments to make future payments of $56 million primarily for natural gas transportation projects. The future payments under these contractual commitments are all expected to be made in 2016.

OTHER COMMITMENTS

SDG&E

In connection with the completion of the Sunrise Powerlink project in 2012, 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 a remaining 54-year period. At December 31, 2015, the present value of these future payments of $117 million has been recorded as a regulatory asset as the amounts represent a cost that is expected to be recovered from customers in the future, and the related liability was $117 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 a 2006 comprehensive legal settlement with the State of California to resolve the Continental Forge litigation 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. There are no specified minimums required, and to date, Sempra Natural Gas has not been required to deliver any natural gas pursuant to this agreement.

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 discuss environmental matters related to the natural gas leak at SoCalGas’ Aliso Canyon natural gas storage facility above under “Legal Proceedings – SoCalGas – Aliso Canyon Natural Gas Storage Facility Gas Leak.”

Other Environmental Issues

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 our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations:

CAPITAL EXPENDITURES FOR ENVIRONMENTAL ISSUES
(Dollars in millions)
	Years ended December 31,
	2015			2014			2013
Sempra Energy Consolidated(1)		$	64		$	45		$	31
SDG&E			24			23			13
SoCalGas			39			21			15

(1)

In cases of non-wholly owned affiliates, includes only our share.

Fluctuations from 2014 to 2015 were primarily due to increased project activities during 2015, including PSEP-related projects at SoCalGas. Fluctuations from 2013 to 2014 were primarily due to increased project activities during 2014, including PSEP-related projects at both SDG&E and SoCalGas and the Aliso Canyon turbine replacement project at SoCalGas. 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, except for those related to the Aliso Canyon natural gas leak as we discuss above under “Legal Proceedings – SoCalGas – Aliso Canyon Natural Gas Storage Facility Gas Leak,” 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 include a 150-acre artificial reef that was dedicated in 2008 and continues in process to meet California Coastal Commission (CCC) acceptance requirements. It is anticipated that the CCC will require expansion of the reef, as the existing reef may be too small to consistently meet the performance standard. The table below shows the status at December 31, 2015, of the California Utilities’ manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP:

STATUS OF ENVIRONMENTAL SITES

	# Sites		# Sites
	completed(1)		in process
SDG&E:
Manufactured-gas sites		3		―
Third-party waste-disposal sites		2		1
SoCalGas:
Manufactured-gas sites		39		3
Third-party waste-disposal sites		5		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 cleanups proceed, we make adjustments as necessary. The following table shows our accrued liabilities for environmental matters at December 31, 2015:

ACCRUED LIABILITIES FOR ENVIRONMENTAL MATTERS
(Dollars in millions)
				Waste			Former fossil-			Other
	Manufactured-			disposal			fueled power			hazardous
	gas sites			sites (PRP)(1)			plants			waste sites			Total(2)
SDG&E(3)		$	―		$	0.9		$	0.7		$	0.5		$	2.1
SoCalGas(4)			23.1			2.0			―			―			25.1
Other			1.8			1.1			―			15.0			17.9
Total Sempra Energy		$	24.9		$	4.0		$	0.7		$	15.5		$	45.1

(1	)	Sites for which we have been identified as a Potentially Responsible Party.
(2	)	Sempra Energy, SDG&E and SoCalGas have accrued $45 million, $2 million and $25 million, respectively, for environmental liabilities as of December 31, 2015. Of these amounts, $24 million, $1 million and $6 million were classified as current liabilities, and $21 million, $1 million and $19 million were classified as noncurrent liabilities on Sempra Energy’s, SDG&E’s and SoCalGas’ Consolidated Balance Sheets, respectively.
(3	)	Does not include SDG&E’s liability for SONGS marine mitigation.
(4	)	Does not include any SoCalGas accrued liabilities for environmental matters for the natural gas leak at the Aliso Canyon facility. We discuss matters related to the leak above under "Legal Proceedings – SoCalGas – Aliso Canyon Natural Gas Storage Facility Gas Leak."

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 CCC to mitigate the damage to the marine environment caused by the cooling-water discharge from SONGS during its operation. SONGS’ early retirement, described in Note 13, does not reduce SDG&E’s mitigation obligation. At December 31, 2015, SDG&E’s share of the estimated mitigation costs remaining to be spent through 2050 is $14 million, which is recoverable in rates and included in Deferred Credits and Other Liabilities on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets.

We discuss renewable energy requirements in Note 14 and greenhouse gas regulation in Note 1.

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 $13.2 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 $50.93 million. This amount is subject to an annual maximum of $7.6 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, subject to a $2.5 million deductible for “each and every loss.” This insurance coverage is provided through Nuclear Electric Insurance Limited (NEIL). The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $9.7 million of retrospective premiums based on overall member claims. See Note 13 under “Settlement with NEIL” for discussion of an agreement between the SONGS co-owners and NEIL to settle all claims under the NEIL policies associated with the SONGS outage.

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.

U.S. DEPARTMENT OF ENERGY (DOE) 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. SDG&E will seek recovery for these costs from the appropriate sources, including, but not limited to, SDG&E’s Nuclear Decommissioning Trusts. SDG&E will also continue to support Edison in its pursuit of legal claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel.

In October 2015, the CCC approved Edison’s application for the proposed expansion of an Independent Spent Fuel Storage Installation (ISFSI) at SONGS. The ISFSI is proposed to be installed beginning in 2016, fully loaded with spent fuel by 2020, and operated until 2049, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The facility would then be decommissioned, and the site restored.

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 of $98 million 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. In September 2014, Edison updated the claim to include another $84 million for costs incurred from January 2011 to December 2013.

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 develops, owns and operates, or holds interests in, electric transmission, distribution and generation infrastructure in Chile and 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 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, Minnesota, Nebraska, Nevada and Pennsylvania to serve wholesale electricity markets in the United States.

Sempra Natural Gas develops, owns and operates, or holds interests in, natural gas pipelines and storage facilities, natural gas distribution utilities and a terminal for the import and export of LNG and sale of natural gas, all within the United States. Sempra Natural Gas also owned and operated the Mesquite Power plant, a natural gas-fired electric generation asset, the remaining 625-MW block of which was sold in April 2015, as we discuss in Note 3.

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.

Common services shared by the business segments are assigned directly or allocated based on various cost factors, depending on the nature of the service provided. Interest income and expense is recorded on intercompany loans. The loan balances and related interest are eliminated in consolidation.

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.

SEGMENT INFORMATION
(Dollars in millions)
	Years ended December 31,
	2015					2014					2013
REVENUES
SDG&E	$	4,219		41	%	$	4,329		39	%	$	4,066		39	%
SoCalGas		3,489		34			3,855		35			3,736		35
Sempra South American Utilities		1,544		15			1,534		14			1,495		14
Sempra Mexico		669		7			818		8			675		6
Sempra Renewables		36		―			35		―			82		1
Sempra Natural Gas		653		6			979		9			908		9
Adjustments and eliminations		(2	)	―			(3	)	―			(2	)	―
Intersegment revenues(1)		(377	)	(3	)		(512	)	(5	)		(403	)	(4	)
Total	$	10,231		100	%	$	11,035		100	%	$	10,557		100	%
INTEREST EXPENSE
SDG&E	$	204				$	202				$	197
SoCalGas		84					69					69
Sempra South American Utilities		32					33					27
Sempra Mexico		23					17					17
Sempra Renewables		3					5					23
Sempra Natural Gas		72					111					116
All other		263					241					241
Intercompany eliminations		(120	)				(124	)				(131	)
Total	$	561				$	554				$	559
INTEREST INCOME
SDG&E	$	―				$	―				$	1
SoCalGas		4					―					―
Sempra South American Utilities		19					14					14
Sempra Mexico		7					4					2
Sempra Renewables		4					1					20
Sempra Natural Gas		75					115					88
All other		―					1					―
Intercompany eliminations		(80	)				(113	)				(105	)
Total	$	29				$	22				$	20
DEPRECIATION AND AMORTIZATION
SDG&E	$	604		48	%	$	530		46	%	$	494		44	%
SoCalGas		461		37			431		37			383		35
Sempra South American Utilities		50		4			55		5			59		5
Sempra Mexico		70		6			64		6			63		6
Sempra Renewables		6		―			5		―			21		2
Sempra Natural Gas		49		4			61		5			81		7
All other		10		1			10		1			12		1
Total	$	1,250		100	%	$	1,156		100	%	$	1,113		100	%
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	284				$	270				$	191
SoCalGas		138					139					116
Sempra South American Utilities		67					58					67
Sempra Mexico		11					5					60
Sempra Renewables		(49	)				(44	)				(19	)
Sempra Natural Gas		28					(20	)				40
All other		(138	)				(108	)				(89	)
Total	$	341				$	300				$	366

SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
	At December 31 or for the years ended December 31,
	2015					2014					2013
EARNINGS (LOSSES)
SDG&E(2)	$	587		43	%	$	507		44	%	$	404		41	%
SoCalGas(3)		419		31			332		29			364		37
Sempra South American Utilities		175		13			172		15			153		15
Sempra Mexico		213		16			192		16			122		12
Sempra Renewables		63		5			81		7			62		6
Sempra Natural Gas		44		3			50		4			64		6
All other		(152	)	(11	)		(173	)	(15	)		(168	)	(17	)
Total	$	1,349		100	%	$	1,161		100	%	$	1,001		100	%
ASSETS(4)
SDG&E	$	16,515		40	%	$	16,260		41	%	$	15,337		41	%
SoCalGas		12,104		29			10,446		26			9,138		25
Sempra South American Utilities		3,235		8			3,379		9			3,531		10
Sempra Mexico		3,783		9			3,486		9			3,243		9
Sempra Renewables		1,441		4			1,334		3			1,214		3
Sempra Natural Gas		5,566		13			6,435		16			7,199		19
All other		734		2			872		2			817		2
Intersegment receivables		(2,228	)	(5	)		(2,561	)	(6	)		(3,314	)	(9	)
Total	$	41,150		100	%	$	39,651		100	%	$	37,165		100	%
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E	$	1,133		36	%	$	1,100		35	%	$	978		38	%
SoCalGas		1,352		43			1,104		35			762		30
Sempra South American Utilities		154		5			174		6			200		8
Sempra Mexico		302		10			325		10			371		14
Sempra Renewables		81		2			190		6			176		7
Sempra Natural Gas		87		3			212		7			83		3
All other		47		1			18		1			2		―
Total	$	3,156		100	%	$	3,123		100	%	$	2,572		100	%
GEOGRAPHIC INFORMATION
Long-lived assets(5):
United States	$	26,132		84	%	$	24,183		84	%	$	22,654		84	%
Mexico		3,160		10			2,821		10			2,597		9
South America		1,652		6			1,746		6			1,784		7
Total	$	30,944		100	%	$	28,750		100	%	$	27,035		100	%

Revenues(6):
United States	$	8,119		79	%	$	8,774		79	%	$	8,478		80	%
South America		1,544		15			1,534		14			1,495		14
Mexico		568		6			727		7			584		6
Total	$	10,231		100	%	$	11,035		100	%	$	10,557		100	%

(1)	Revenues for reportable segments include intersegment revenues of $9 million, $75 million, $101 million, and $192 million for 2015, $10 million, $69 million, $91 million and $342 million for 2014, and $10 million, $70 million, $91 million and $232 million for 2013 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.
(2)	For 2013, amount is after preferred dividends and call premium on preferred stock.
(3)	After preferred dividends.
(4)	December 31, 2014 and 2013 have been adjusted for the retrospective adoption of ASU 2015-03.
(5)	Includes net property, plant and equipment and investments.
(6)	Amounts are based on where the revenue originated, after intercompany eliminations.

NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED)

We provide quarterly financial information for Sempra Energy Consolidated, SDG&E and SoCalGas below:

SEMPRA ENERGY
(In millions, except per share amounts)
	Quarters ended
	March 31		June 30		September 30		December 31
2015:
Revenues	$	2,682	$	2,367	$	2,481	$	2,701
Expenses and other income	$	2,076	$	1,971	$	2,211	$	2,269

Net income	$	458	$	320	$	282	$	388
Earnings attributable to Sempra Energy	$	437	$	295	$	248	$	369

Basic per-share amounts(1):
Net income	$	1.85	$	1.29	$	1.14	$	1.56
Earnings attributable to Sempra Energy	$	1.76	$	1.19	$	1.00	$	1.48
Weighted average common shares outstanding		247.7		248.1		248.4		248.7

Diluted per-share amounts(1):
Net income	$	1.83	$	1.27	$	1.12	$	1.54
Earnings attributable to Sempra Energy	$	1.74	$	1.17	$	0.99	$	1.47
Weighted average common shares outstanding		251.2		251.5		251.0		251.5
2014:
Revenues	$	2,795	$	2,678	$	2,815	$	2,747
Expenses and other income	$	2,408	$	2,302	$	2,368	$	2,433

Net income	$	266	$	292	$	383	$	321
Earnings attributable to Sempra Energy	$	247	$	269	$	348	$	297

Basic per-share amounts(1):
Net income	$	1.09	$	1.19	$	1.56	$	1.31
Earnings attributable to Sempra Energy	$	1.01	$	1.10	$	1.41	$	1.21
Weighted average common shares outstanding		245.3		245.7		246.1		246.4

Diluted per-share amounts(1):
Net income	$	1.07	$	1.17	$	1.53	$	1.28
Earnings attributable to Sempra Energy	$	0.99	$	1.08	$	1.39	$	1.18
Weighted average common shares outstanding		249.7		250.1		250.8		251.3

(1)

Earnings per share are computed independently for each of the quarters and therefore may not sum to the total for the year.

In the first quarter of 2015, SoCalGas adopted a CPUC decision in the TCAP requiring SoCalGas to recognize annual authorized revenue for core natural gas customers using seasonal factors established in the TCAP, instead of recognizing such revenue ratably over the year as was previously required. While this seasonalization caused variability in comparable revenue and earnings from quarter to quarter within the year, it did not impact full-year 2015 results, nor have any impact on cash flows. Accordingly, substantially all of SoCalGas’ annual earnings were recognized in the first and fourth quarters of the year.

Compared to the same periods in 2014, this “seasonalization” at SoCalGas impacted Revenues, Net Income and Earnings Attributable to Sempra Energy as follows:

§	For the first quarter of 2015, $163 million higher Revenues and $113 million higher Net Income and Earnings Attributable to Sempra Energy

§	For the second quarter of 2015, $72 million lower Revenues and $48 million lower Net Income and Earnings Attributable to Sempra Energy

§	For the third quarter of 2015, $158 million lower Revenues and $113 million lower Net Income and Earnings Attributable to Sempra Energy

§	For the fourth quarter of 2015, $67 million higher Revenues and $48 million higher Net Income and Earnings Attributable to Sempra Energy

In addition to the impact of seasonalization, Revenues and Expenses and Other Income decreased in each quarter of 2015 compared to 2014 partly due to lower average cost of natural gas at SoCalGas. In the first quarter of 2015, Revenues and Expenses and Other Income decreased due to lower demand for natural gas primarily from warmer weather in the first quarter of 2015 compared to the same period in 2014. In the fourth quarter of 2015, Revenues and Expenses and Other Income increased due to higher demand for natural gas primarily from cooler weather in the fourth quarter of 2015 compared to the same period in 2014.

In each of the quarters of 2015 compared to the same periods in 2014, Revenues and Expenses and Other Income decreased as a result of lower cost of electric fuel and purchased power at SDG&E, including the impact of declining natural gas prices offset by an increase from the incremental purchase of renewable energy at higher prices.

In the second quarter of 2015, Expenses and Other Income were favorably impacted by $61 million and Net Income and Earnings Attributable to Sempra Energy were favorably impacted by $36 million due to the sale of the remaining 625-MW block of the 1,250-MW Mesquite Power natural gas-fired power plant, as we discuss in Note 3.

In the first and fourth quarters of 2015 and 2014, SDG&E recorded adjustments to the SONGS plant closure loss, as we discuss in Note 13 under “Settlement Agreement to Resolve the CPUC’s Order Instituting Investigation (OII) into the SONGS Outage (SONGS OII) – Accounting and Financial Impacts.”

In the third quarter of 2014, Net Income and Earnings Attributable to Sempra Energy included $25 million tax benefit due to the release of a Louisiana state valuation allowance against a deferred tax asset associated with Cameron LNG developments.

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
2015:
Operating revenues	$	966		$	972		$	1,230		$	1,051
Operating expenses		684			745			930			802
Operating income	$	282		$	227		$	300		$	249

Net income	$	151		$	130		$	182		$	143
(Earnings) losses attributable to noncontrolling interest		(4	)		(4	)		(12	)		1
Earnings attributable to common shares	$	147		$	126		$	170		$	144
2014:
Operating revenues	$	987		$	1,063		$	1,233		$	1,046
Operating expenses		766			821			957			826
Operating income	$	221		$	242		$	276		$	220

Net income	$	101		$	129		$	169		$	128
Earnings attributable to noncontrolling interest		(2	)		(6	)		(12	)		―
Earnings attributable to common shares	$	99		$	123		$	157		$	128

In each of the quarters of 2015 compared to the same periods in 2014, Operating Revenues and Operating Expenses decreased as a result of lower cost of electric fuel and purchased power, including the impact of declining natural gas prices offset by an increase from the incremental purchase of renewable energy at higher prices. The decreases in Operating Revenues were partially offset by increases from CPUC-authorized 2015 attrition and higher authorized revenues from electric transmission, both of which impacted Net Income and Earnings Attributable to Common Shares. In addition, Operating Revenues and Operating Expenses were higher due to authorized revenues, starting in 2015, for the recovery of the SONGS regulatory assets pursuant to an amended settlement agreement approved by the CPUC in 2014.

SOCALGAS
(Dollars in millions)
	Quarters ended
	March 31		June 30			September 30			December 31
2015:
Operating revenues	$	1,048	$	780		$	620		$	1,041
Operating expenses		728		686			633			834
Operating income (loss)	$	320	$	94		$	(13	)	$	207

Net income (loss)	$	214	$	71		$	(8	)	$	143
Dividends on preferred stock		―		(1	)		―			―
Earnings (losses) attributable to common shares	$	214	$	70		$	(8	)	$	143
2014:
Operating revenues	$	1,085	$	917		$	855		$	998
Operating expenses		956		795			702			881
Operating income	$	129	$	122		$	153		$	117

Net income	$	78	$	81		$	98		$	76
Dividends on preferred stock		―		(1	)		―			―
Earnings attributable to common shares	$	78	$	80		$	98		$	76

Compared to the same periods in 2014, Operating Revenues, Net Income and Earnings Attributable to Common Shares were impacted by seasonalization of interim period recognition of annual authorized revenue for core natural gas customers as follows:

§	For the first quarter of 2015, $163 million higher Operating Revenues and $113 million higher Net Income and Earnings

§	For the second quarter of 2015, $72 million lower Operating Revenues and $48 million lower Net Income and Earnings

§	For the third quarter of 2015, $158 million lower Operating Revenues and $113 million lower Net Income and Earnings

§	For the fourth quarter of 2015, $67 million higher Operating Revenues and $48 million higher Net Income and Earnings

In addition to the impact of seasonalization, Operating Revenues and Operating Expenses decreased in each quarter of 2015 compared to 2014 primarily due to lower average cost of natural gas. In the first quarter of 2015, Operating Revenues and Operating Expenses decreased due to lower demand for natural gas primarily from warmer weather in the first quarter of 2015 compared to the same period in 2014. In the fourth quarter of 2015, Operating Revenues and Operating Expenses increased due to higher demand for natural gas primarily from cooler weather in the fourth quarter of 2015 compared to the same period in 2014

In each of the quarters of 2015 compared to the same periods in 2014, Operating Revenues, Net Income and Earnings Attributable to Common Shares included higher CPUC-authorized 2015 attrition.

In the third quarter of 2015, Net Loss was partially offset by favorable resolution of prior years’ income tax items.

NOTE 18. SUBSEQUENT EVENT

SEMPRA MEXICO

Asset Held for Sale, Power Plant

In February 2016, management approved a plan to market and sell Sempra Mexico’s Termoeléctrica de Mexicali, a 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As a result, in February 2016, we stopped depreciating the plant and classified the plant as an asset held for sale. The carrying value at December 31, 2015 was $262 million. Although we believe fair value approximates or exceeds carrying value of the asset, in the event that the estimated sales price from the planned sale of Termoeléctrica de Mexicali is less than the carrying value, we may recognize an impairment loss in our results of operations.

GLOSSARY


2010 Tax Act	Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010	Cox	Cox Communications
2012 Tax Act	American Taxpayer Relief Act of 2012	CPCN	Certificate of Public Convenience and Necessity
2014 Tax Act	Tax Increase Prevention Act of 2014	CPUC	California Public Utilities Commission
2015 Tax Act	Protecting Americans from Tax Hikes Act of 2015	CRE	Comisión Reguladora de Energía (Energy Regulatory Commission) (Mexico)
A4NR	Alliance for Nuclear Responsibility	CRRs	Congestion revenue rights
AB	Assembly Bill	DCE	Decommissioning cost estimate
AFUDC	Allowance for funds used during construction	DERS	Distributed Energy Resources Services
ALJ	Administrative Law Judge	DOE	U.S. Department of Energy
AOCI	Accumulated other comprehensive income (loss)	DOGGR	California Department of Conservation's Division of Oil, Gas, and Geothermal Resources
ARO	Asset retirement obligation	DWR	California Department of Water Resources
ASU	Accounting Standards Update	Ecogas	Ecogas México, S. de R.L. de C.V.
Bay Gas	Bay Gas Storage Company, Ltd.	Edison	Southern California Edison Company
Bcf	Billion cubic feet	EIA	Environmental impact authorization
Black-Scholes model	Black-Scholes option-pricing model	EIR/EIS	Environmental impact report/Environmental impact statement
BMV	La Bolsa Mexicana de Valores, S.A.B. de C.V. (Mexican Stock Exchange)	Eletrans	Eletrans, collectively for Eletrans S.A. and Eletrans II S.A.
Cal Fire	California Department of Forestry and Fire Protection	EMA	Energy Management Agreement
California Utilities	San Diego Gas & Electric Company and Southern California Gas Company	Enova	Enova Corporation
Cameron LNG JV	Cameron LNG Holdings, LLC	EPC	Engineering, procurement and construction
CARB	California Air Resources Board	EPS	Earnings per common share
CARE	California Alternate Rates for Energy	ERRA	Energy Resource Recovery Account
CCC	California Coastal Commission	EV	Electric vehicle
CCM	Cost of capital adjustment mechanism	FERC	Federal Energy Regulatory Commission
CFCA	Core Fixed Cost Account	Final 2012 GRC Decision	Final CPUC decision on 2012 General Rate Case
CFE	Comisión Federal de Electricidad (Federal Electricity Commission) (Mexico)	FTA	Free Trade Agreement
CFTC	U.S. Commodity Futures Trading Commission	Gazprom	Gazprom Marketing & Trading Mexico
Chilquinta Energía	Chilquinta Energía S.A. and its subsidiaries	GCIM	Gas cost incentive mechanism
CHP	Combined heat and power	GdC	Gasoductos de Chihuahua
Citizens	Citizens Sunrise Transmission, LLC	GHG	Greenhouse gas
CLF	Chilean Unidad de Fomento	GRC	General Rate Case
CNE	Comisión Nacional de Energía (National Energy Commission) (Chile)	HMRC	United Kingdom's Revenue and Customs Department
CNF	Cleveland National Forest	HRA	Health Reimbursement Account
COFECE	Comisión Federal de Competencia Económica (Mexican Competition Commission)	IEnova	Infraestructura Energética Nova, S.A.B. de C.V.
Con Edison Development	Consolidated Edison Development	IFMP	Irradiated fuel management plan

GLOSSARY (CONTINUED)


IFRS	International Financial Reporting Standards	NOL	Net operating loss
IOUs	Investor-owned utilities	NRC	Nuclear Regulatory Commission
IRS	Internal Revenue Service	NYK	Nippon Yusen Kabushiki Kaisha
ISFSI	Independent spent fuel storage installation	OCI	Other comprehensive income (loss)
ISO	California Independent System Operator, also known as CAISO	OII	Order Instituting Investigation
ITC	Investment tax credits	OMEC	Otay Mesa Energy Center
JBIC	Japan Bank for International Cooperation	OMEC LLC	Otay Mesa Energy Center LLC
JP Morgan	J.P. Morgan Chase & Co.	ORA	Office of Ratepayer Advocates
kV	Kilovolt	OSINERGMIN	Organismo Supervisor de la Inversión en Energía y Minería (Energy and Mining Investment Supervisory Body) (Peru)
LA County DPH	Los Angeles County Department of Public Health	Otay Mesa VIE	Otay Mesa Energy Center LLC
LA Storage	LA Storage, LLC	OTC	Over-the-counter
Liberty	Liberty Gas Storage, LLC	PBOP	Other postretirement benefit plans
LIFO	Last-in first-out	PBOP plan trusts	Other postretirement benefit plan trusts
LNG	Liquefied natural gas	PCB	Polychlorinated Biphenyl
Luz del Sur	Luz del Sur S.A.A. and its subsidiaries	PCRB	Pollution Control Revenue Bonds
MLP	Master limited partnership	PE	Pacific Enterprises
MBFC	Mississippi Business Finance Corporation	PEMEX	Petróleos Mexicanos (Mexican state-owned oil company)
Mcf	Thousand cubic feet	PFM	Petition for modification
MDL	Multi-District Litigation	PG&E	Pacific Gas and Electric Company
Mercuria	Mercuria Energy Europe Trading Limited	PLR	Private Letter Ruling
MHI	Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc.	PPA	Power purchase agreement
Mississippi Hub	Mississippi Hub, LLC	PRP	Potentially Responsible Party
MMBtu	Million British thermal units (of natural gas)	PSDAR	Post-shutdown decommissioning activities report
MMcf	Million cubic feet	PSEP	Pipeline Safety Enhancement Plan
MMCRP	Mitigation Monitoring, Compliance, and Reporting Program	PTC	Production tax credit
Mobile Gas	Mobile Gas Service Corporation	RAMP	Risk Assessment Mitigation Phase
MOU	Memorandum of understanding	RBS	The Royal Bank of Scotland plc
Mtpa	Million tonnes per annum	RBS SEE	RBS Sempra Energy Europe
MW	Megawatt	RBS Sempra Commodities	RBS Sempra Commodities LLP
MWh	Megawatt hour	RECs	Renewable energy certificates
NDT	Nuclear Decommissioning Trusts	REX	Rockies Express pipeline
NEIL	Nuclear Electric Insurance Limited	Rockies Express	Rockies Express Pipeline LLC
NEM	Net energy metering	ROE	Return on equity
NEXI	Nippon Export and Investment Insurance	ROR	Rate of return

GLOSSARY (CONTINUED)


RPS	Renewables Portfolio Standard	SWPL	Southwest Powerlink
RSAs	Restricted stock awards	Tallgrass	Tallgrass Energy Partners, L.P.
RSUs	Restricted stock units	Tangguh PSC	Tangguh PSC Contractors
S-MAP	Safety Model Assessment Proceeding	Tax Reform Bill	2014 Chilean Tax Reform Bill
S&P	Standard & Poor's	TCAP	Triennial Cost Allocation Proceeding
San Isidro pipeline	San Isidro – Samalayuca pipeline	Tecnored	Tecnored S.A.
SAESA	Sociedad Austral de Electricidad Sociedad Anónima	Tecsur	Tecsur S.A.
SB	Senate Bill	TIMP	Transmission Integrity Management Program
SCAQMD	South Coast Air Quality Management District	TO3	Electric Transmission Formula Rate
SCGC	Southern California Generation Coalition	TO4	Electric Transmission Formula Rate
SDG&E	San Diego Gas & Electric Company	TSR	Total Shareholder Return
Securities Act	The U.S. Securities Act of 1933	TURN	The Utility Reform Network
SEDATU	Secretaría de Desarrollo Agrario, Territorial y Urbano	USFS	United States Forest Service
SEMARNAT	Mexican environmental protection agency	U.S. GAAP	Accounting principles generally accepted in the United States of America
SFP	Secondary financial protection	VaR	Value at Risk
SGRP	Steam Generator Replacement Project	VAT	Value-added tax
SGS	Sempra Global Services, Inc.	VEBA	Voluntary Employee Beneficiary Association
Shell	Shell México Gas Natural	VIE	Variable interest entity
SoCalGas	Southern California Gas Company	WEMA	Wildfire Expense Memorandum Account
SONGS	San Onofre Nuclear Generating Station	Williams	Williams Midstream Natural Gas Liquids, Inc.
SONGS OII	CPUC’s Order Instituting Investigation (OII) into the SONGS Outage	Willmut Gas	Willmut Gas Company
SUE	Super user electric	Woodside	Woodside Petroleum Ltd.

Exhibit 21.1

Exhibit 21.1

Sempra Energy

Schedule of Certain Subsidiaries

at December 31, 2015


Subsidiary	State of Incorporation or Other Jurisdiction
AEI Asociacion en Participacion	Peru
Enova Corporation	California
Infraestructura Energetica Nova, S. A.B.	Mexico
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 International Holdings N.V.	Netherlands
Sempra Energy Holdings XI B.V.	Netherlands
Sempra Global	Delaware
Semco Holdco, S. de R.L. de C.V.	Mexico
Southern California Gas Company	California

Sempra Energy Ex 31.1

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, 2016

/s/ Debra L. Reed

Debra L. Reed

Chief Executive Officer

Sempra Energy Ex 31.2

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, 2016

/s/ Joseph A. Householder

Joseph A. Householder

Chief Financial Officer

SDG&E Ex 31.3

EXHIBIT 31.3

CERTIFICATION

I, J. Walker Martin, 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, 2016

/s/ J. Walker Martin

J. Walker Martin

Chief Executive Officer

SDG&E Ex 31.4

EXHIBIT 31.4

CERTIFICATION

I, Bruce A. Folkmann, 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, 2016

/s/ Bruce A. Folkmann

Bruce A. Folkmann

Chief Financial Officer

SCG Ex 31.5

EXHIBIT 31.5

CERTIFICATION

I, Dennis V. Arriola, 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, 2016

/s/ Dennis V. Arriola

Dennis V. Arriola

Chief Executive Officer

SCG Ex 31.6

EXHIBIT 31.6

CERTIFICATION

I, Bruce A. Folkmann, 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, 2016

/s/ Bruce A. Folkmann

Bruce A. Folkmann

Chief Financial Officer

Sempra Energy Ex 32.1

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, 2015 (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, 2016

/s/ Debra L. Reed

Debra L. Reed

Chief Executive Officer

Sempra Energy Ex 32.2

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, 2016

/s/ Joseph A. Householder

Joseph A. Householder

Chief Financial Officer

SDG&E Ex 32.3

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, 2016

/s/ J. Walker Martin

J. Walker Martin

Chief Executive Officer

SDG&E Ex 32.4

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, 2016

/s/ Bruce A. Folkmann

Bruce A. Folkmann

Chief Financial Officer

SCG Ex 32.5

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, 2016

/s/ Dennis V. Arriola

Dennis V. Arriola

Chief Executive Officer

SCG Ex 32.6

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, 2016

/s/ Bruce A. Folkmann

Bruce A. Folkmann

Chief Financial Officer