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.)

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).

□   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 (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)

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)

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)

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)

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

§   $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.

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, weprovide 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.

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.

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 summarizevariations 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 thatthese 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.

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. For additional discussion, see “Risk Factors” in the 2015 Annual Report on Form 10-K.

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.

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.

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.

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.

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.

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, and our results of operations, cash flows and financial condition may be materially adversely affected.

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 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 establishpolicy, 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 14of 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

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 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.

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.

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 expressedan unqualified opinion on those financial statements.

/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.

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 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.

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

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.

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 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.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southern California Gas Company and subsidiaries as of December 31, 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

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 Utilitiesare 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. Theshares 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.

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.

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.

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. 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.

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., which we discuss further in Note 3.

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.

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.

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 Energíais 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 Energíahas 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, 6,148,009shares 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

measurement

inputs

Investment in

Energía Sierra Juárez

$

26

(1

)

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	to	$	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	to	$	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	to	$	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	to	$	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	to	$	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.				$	45	§	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

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 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.

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 (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.

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.

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’scontribution 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.

4.   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.

6.   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.

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.”

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.