ITEM 1. BUSINESS

This report on Form 10-K includes information for the following separate registrants:

References in this report to “we,” “our,” “us,” “our company” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by the context. SDG&E and SoCalGas are collectively referred to as the California Utilities.

OVERVIEW

We are a Fortune 500 energy-services holding company. Our operating units invest in, develop and operate energy infrastructure, and provide electric and gas services to customers in North and South America. We were formed in 1998 through a business combination of Enova and PE, the holding companies of our regulated public utilities in California: SDG&E, which began operations in 1881, and SoCalGas, which began operations in 1867. Since our formation in 1998, we have expanded our investment in regulated utility operations through business acquisitions in 2011 in South America. Additionally, in response to changes in Mexican gas regulation in 1995, we entered the energy infrastructure business in Mexico through what is now known as IEnova, the first energy infrastructure company to be listed on the Mexican Stock Exchange. Our energy infrastructure footprint continues to expand across the U.S., through renewable energy generation projects and LNG and natural gas midstream projects and assets. In August 2017, we entered into the Merger Agreement to acquire an indirect ownership interest in Oncor, a regulated electric distribution and transmission business that operates the largest distribution and transmission system in Texas. We expect the Merger to close in the first half of 2018.

We have two principal operating units, Sempra Utilities and Sempra Infrastructure. Sempra Utilities includes SDG&E, SoCalGas and Sempra South American Utilities. Sempra Infrastructure includes Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream. If the Merger is consummated, our investment in Oncor will be included in a new reportable segment within the Sempra Utilities operating unit.

All references to “Sempra Utilities” and “Sempra Infrastructure” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name. Sempra Infrastructure also owns or owned (during periods presented in this report) regulated utilities that are not included in our references to the Sempra Utilities. We provide financial information about all our reportable segments and about the geographic areas in which we do business in Note 16 of the Notes to Consolidated Financial Statements.

Business Strategy

Our objective is to increase shareholder value by developing, investing in and operating utilities and long-term-contracted energy infrastructure assets and operating our companies in a safe and reliable manner.

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

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 on a long-term basis. We have a robust capital program and take a disciplined approach to deploying this capital to areas that fit our strategy and are designed to create shareholder value.

PENDING ACQUISITION

Energy Future Holdings Corp.

On August 21, 2017, Sempra Energy entered into an Agreement and Plan of Merger, as supplemented by a Waiver Agreement dated October 3, 2017 and an amendment dated February 15, 2018 (together referred to as the Merger Agreement), with Energy Future Holdings Corp., the indirect owner of 80.03 percent of Oncor Electric Delivery Company LLC. Oncor is a regulated electric distribution and transmission business that operates the largest distribution and transmission system in Texas. Following closing, this acquisition will expand our regulated earnings base, while serving as a platform for future growth in the Texas energy market and U.S. Gulf Coast region. Under the Merger Agreement, we will pay the Merger Consideration of $9.45 billion in cash. Pursuant to the Merger Agreement and subject to the satisfaction of certain closing conditions described below, EFH will be merged with an indirect subsidiary of Sempra Energy, with EFH continuing as the surviving company and an indirect, wholly owned subsidiary of Sempra Energy (the Merger). The terms and conditions of the Merger Agreement (and a related letter agreement with Oncor) are described in more detail in Sempra Energy’s current reports on Form 8-K filed with the SEC on August 25, 2017, August 28, 2017 and October 6, 2017. The amendment dated February 15, 2018 (the Amendment) was made in connection with a settlement agreement, dated as of February 5, 2018, by and among the parties to the Merger Agreement and certain of their subsidiaries. The Amendment amends certain merger terms, in accordance with the settlement agreement, that relate to Oncor dividend payments and certain adjustments to the Merger Consideration. The Amendment is provided in its entirety by reference to Exhibit 2.1.3, filed herewith.

Ring-Fencing

In April 2014, EFH and the substantial majority of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the Bankruptcy Court. The bankruptcy does not include Oncor or Oncor Holdings. Oncor Holdings owns 80.03 percent of Oncor and is indirectly wholly owned by EFH. Certain existing “ring-fencing” measures, governance mechanisms and restrictions will remain in effect following the Merger, which are intended to enhance Oncor Holdings’ and Oncor’s separateness from their owners and to mitigate the risk that these entities would be negatively impacted by the bankruptcy of, or other adverse financial developments affecting, EFH or its other subsidiaries or the owners of EFH. In accordance with the ring-fencing measures and commitments made by Sempra Energy as part of the Joint Application to the PUCT for regulatory approval of the Merger, Sempra Energy and Oncor will be subject to certain restrictions following the Merger. Sempra Energy will not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and restrictions, as well as the Stipulation discussed below and elsewhere herein, will limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important corporate issues and actions. Thus, Oncor Holdings and Oncor will continue to be managed independently (i.e., ring-fenced). Upon consummation of the Merger, although we will consolidate EFH, EFH will continue to account for its ownership in Oncor Holdings as an equity method investment.

Settlement Agreement Regarding Joint Application

On October 5, 2017, Sempra Energy and Oncor filed a Joint Application with the PUCT and an application with the FERC seeking approval of the Merger. In December 2017, Sempra Energy and Oncor entered into a comprehensive Stipulation with the Staff of the PUCT, the Office of the Public Utility Counsel, the Steering Committee of Cities Served by Oncor and the Texas Industrial Energy Consumers, reflecting the parties’ settlement of all issues in the PUCT proceeding regarding the Joint Application. Pursuant to the Stipulation, the parties have agreed that Sempra Energy’s acquisition of EFH is in the public interest and will bring substantial benefits. The parties to the Stipulation also agreed to ask the PUCT to approve the Merger, consistent with the governance, regulatory and operating commitments outlined in the Stipulation.

The Stipulation includes regulatory commitments by us, as described below and elsewhere herein, most of which are similar to the regulatory commitments made by us as part of the Joint Application and are consistent with the “ring-fencing” measures currently in place. Sempra Energy and Oncor are entitled to seek modifications of the PUCT order to be entered in the proceedings regarding the Joint Application, which modifications would be subject to PUCT approval.

While Oncor’s Limited Liability Company Agreement generally provides that Oncor will make quarterly distributions to its members equal to the net income of Oncor, subject to certain exceptions, and Oncor Holdings’ Limited Liability Company Agreement generally provides that Oncor Holdings will make quarterly distributions to its member equal to the dividends received by Oncor, subject to certain exceptions, the Stipulation provides a number of circumstances in which Oncor is not permitted to make dividends or other distributions (except for contractual tax payments). In addition, the Stipulation provides that the respective boards of Oncor and Oncor Holdings will control each respective company’s dividend policy (and any changes to such policy must be approved by a majority of its independent directors), issuances of dividends and other distributions (except for contractual tax payments). The Stipulation also provides that the respective boards of Oncor and Oncor Holdings will control each respective company’s debt issuances, capital expenditures, operation and maintenance expenditures, management and service fees, and, subject to certain limitations, appointment or removal of board members.

If the PUCT does not accept the Stipulation as presented, or issues an order inconsistent with the terms of the Stipulation, the parties have agreed that any party adversely affected by the alteration has the right to withdraw from the Stipulation and to exercise all rights available to such party under the law.

On January 5, 2018, Oncor, Sempra Energy and Staff of the PUCT jointly filed with the PUCT, requesting that the PUCT approve the Merger consistent with the Stipulation. As of January 31, 2018, all 10 intervening parties, including the Staff of the PUCT, agreed to the Stipulation.

We discuss the Merger and financing of the Merger Consideration, ring-fencing measures, additional regulatory commitments, governance mechanisms and restrictions, as well as the Stipulation, in Notes 3 and 18 of the Notes to Consolidated Financial Statements, “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.”

Closing Conditions

The Merger is subject to customary closing conditions, including the approval of the PUCT. Certain conditions, such as approval from the Bankruptcy Court, the FERC, the Vermont Department of Financial Regulation and receipt of a private letter ruling from the IRS, have been satisfied. If the required governmental consents and approvals are not received, or if they are not received on terms that satisfy the closing conditions in the Merger Agreement, the Merger could be abandoned, delayed or restructured.

The Merger Agreement provides that it will terminate if the Merger is not consummated by April 18, 2018, subject to limited exceptions. One of those exceptions provides that, if the Merger is not consummated because the requisite PUCT approval has not been obtained by April 18, 2018, but such approval is still capable of being obtained within 90 days thereafter, the April 18, 2018 date shall be extended for 90 days for purposes of continuing to pursue such approval, unless otherwise agreed by EFH and EFIH (acting together) and Sempra Energy.

We currently expect that the Merger will close in the first half of 2018, although there can be no assurance that the Merger will be completed on that timetable, or at all.

OUR SEGMENTS

No single customer accounted for 10 percent or more of Sempra Energy’s consolidated revenues in 2017, 2016 or 2015.

SDG&E

SDG&E is a regulated public utility that provides electric services to a population of approximately 3.6 million and natural gas services to approximately 3.3 million of that population, covering a 4,100 square mile service territory in Southern California that encompasses San Diego County and an adjacent portion of southern Orange County.

Electric Utility Operations

Customers and Demand. SDG&E provides electric services through the generation, transmission and distribution of electricity to the following customer classes:

No single customer accounted for 10 percent or more of SDG&E’s revenues from electricity sold in 2017, 2016 or 2015.

SDG&E’s system average rate is based on authorized revenue requirements divided by authorized sales volumes. SDG&E’s system average rate was $0.238, $0.206 and $0.218 per kWh in 2017, 2016 and 2015, respectively. The 2017 increase compared to 2016 was primarily the result of undercollected power costs in 2016. The 2016 decrease compared to 2015 was driven by the inclusion in 2015 of undercollections associated with activities prior to 2015, including the delay in implementing into rates the increases associated with the 2012 GRC. A significant proportion of SDG&E’s costs to operate are independent of sales volumes, which can contribute to system average rate variances as sales volumes change.

An electric utility’s system average rate can be affected by numerous factors, which are not necessarily common to other utilities regionally or nationally. In general, the utilization of a typical electric utility’s distribution assets is significantly less than their capacity because the assets are designed to meet peak needs. Compared to the typical utility in the U.S., SDG&E delivers a higher relative percentage of its total power sold to residential customers, who on average consume less power than an average commercial customer. San Diego’s mild climate and SDG&E’s robust energy efficiency programs also contribute to lower consumption by our customers. In addition, rooftop solar installations, especially in recent years, have reduced residential and commercial volumes sold by SDG&E. As of December 31, 2017, 2016 and 2015, the residential and commercial rooftop solar capacity in SDG&E’s territory totaled 836 MW, 694 MW and 496 MW, respectively. All these factors contribute to generally higher system average rates, where the cost of building and operating our assets is spread over a relatively smaller sales volume.

In addition to these factors, SDG&E’s CPUC-approved rate design includes a tiered residential pricing structure. We discuss electric rate reform further in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.”

Demand for electricity is dependent on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preference, environmental regulations, legislation, renewable power generation, the effectiveness of energy efficiency programs, demand-side management goals and distributed generation resources. California’s energy policy supports increased electrification, particularly electrification of vehicles, which could result in significant increases in sales volumes in the coming years. Other external factors, such as the price of purchased power, the use of hydroelectric power, development of renewable energy resources, development of new natural gas supply sources, demand for natural gas, and general economic conditions, can also result in significant shifts in the market price of electricity, which may in turn impact demand. Demand for electricity is also impacted by seasonal weather patterns (or “seasonality”), tending to increase in the summer months to meet cooling load and in the winter months to meet heating load.

Electric Resources. To meet customer demand, SDG&E procures power from its own electric generation facilities and from other suppliers through CPUC-approved purchased-power contracts or through purchases on a spot basis. SDG&E’s supply as of December 31, 2017 is as follows:

SDG&E is required to interconnect with and purchase power from QFs, a class of generating facilities established by the Public Utility Regulatory Policies Act of 1978, at rates that do not exceed SDG&E’s avoided cost. For SDG&E, QFs include cogeneration facilities, which produce electricity and another form of useful thermal energy (such as heat or steam) used for industrial, commercial, residential or institutional purposes. Charges under most of the contracts with QFs are based on what it

would incrementally cost SDG&E to produce the power or procure it from other sources. Charges under the contracts with other suppliers are for firm and as-generated energy, and are based on the amount of energy received or are tolls based on available capacity. Tolling contracts are purchased-power contracts under which SDG&E provides natural gas for generation to the energy supplier. The prices under these contracts include 193 MW at prices that are based on the market value at the time the contracts were negotiated.

SDG&E provides bundled electric procurement service through various resources that are typically procured on a long-term basis, as shown above. While SDG&E provides such procurement service for the majority of its customer load, customers do have the ability to receive procurement service from a load serving entity other than SDG&E, through programs such as DA and CCA. DA is currently closed to new entrants, but utility customers can receive procurement through CCA, if the customer’s local jurisdiction (city) offers such a program. A number of cities in our service territory have expressed interest in CCA, which, if widely adopted, could result in substantial reductions in the load we are required to serve. For example, Solana Beach (representing less than 1 percent of SDG&E’s customer accounts) has elected to begin CCA service in 2018. When customers are served by another load serving entity, SDG&E no longer serves this departing load and the associated costs of the utility’s procured resources are otherwise borne by its remaining bundled procurement customers. The CPUC has tried to address this issue by adopting rate mechanisms that attempt to ensure bundled customer indifference in the event of departing load, but these existing mechanisms may not be sufficient to address the full extent of the potential cost shift in the event of significant departing load, and SDG&E bears some risk that its procured resources could become stranded without recovery of the associated costs.

Natural Gas Supply for Generation Facilities. SDG&E procures natural gas under short-term contracts for its owned generation facilities and for certain tolling contracts associated with purchased-power arrangements. Purchases are from various southwestern U.S. suppliers and are primarily priced based on published monthly bid-week indices.

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

Electric Transmission and Distribution System. Service to SDG&E’s customers is supported by its electric transmission and distribution system. At December 31, 2017, SDG&E’s electric transmission and distribution facilities included substations and overhead and underground lines. These electric facilities are in San Diego, Imperial and Orange counties of California, and in Arizona and Nevada. The facilities consist of 2,090 miles of transmission lines, 23,479 miles of distribution lines and 160 substations. Periodically, various areas of the service territory require expansion to accommodate customer growth, reliability and safety.

SDG&E’s 500-kV Southwest Powerlink transmission line, which is shared with Arizona Public Service Company and Imperial Irrigation District, extends from Palo Verde, Arizona to San Diego, California. SDG&E’s share of the line is 1,162 MW, although it can be less under certain system conditions. SDG&E’s Sunrise Powerlink is a 500-kV transmission line constructed and operated by SDG&E with import capability of 1,000 MW of power.

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

Edison’s transmission system is connected to SDG&E’s system via five 230-kV transmission lines.

Competition. SDG&E faces competition to serve its customer load from the growth in distributed and local power generation, including rooftop solar installations, battery storage, and the corresponding decrease in demand for power delivered through SDG&E’s electric transmission and distribution system and from possible departing retail load resulting from customers transferring to DA and CCA. SDG&E does not earn any return on commodity sales.

Natural Gas Utility Operations

We discuss SDG&E’s natural gas utility operations below in “California Utilities’ Natural Gas Utility Operations.”

Key Noncash Performance Indicators

We use certain financial and non-financial metrics to measure how effective our businesses are in achieving their key business objectives. For SDG&E, these key noncash performance indicators include number of customers, electricity sold, system average rate and natural gas volumes transported and sold. Additional noncash performance indicators include goals related to safety,

customer service, customer reputation, environmental considerations (including quantities of renewable energy purchases), on-time and on-budget completion of major projects and initiatives, and service reliability.

SoCalGas

SoCalGas is a regulated public utility that owns and operates a natural gas distribution, transmission and storage system that supplies natural gas to a population of approximately 21.8 million, covering a 24,000 square mile service territory that encompasses Southern California and portions of central California (excluding San Diego County, the city of Long Beach and the desert area of San Bernardino County).

Natural Gas Utility Operations

We provide additional information on SoCalGas’ natural gas utility operations below in “California Utilities’ Natural Gas Utility Operations.”

Key Noncash Performance Indicators

Key noncash performance indicators for SoCalGas include number of customers and natural gas volumes transported and sold. Additional noncash performance indicators include goals related to safety, customer service, customer reputation, environmental considerations, natural gas demand by customer segment, on-time and on-budget completion of major projects and initiatives, and service reliability.

California Utilities Natural Gas Utility Operations

Customers and Demand

SoCalGas and SDG&E sell, distribute and transport natural gas. SoCalGas purchases and stores natural gas for its core customers and SDG&E’s core customers on a combined portfolio basis and provides natural gas storage services for others.

For regulatory purposes, end-use customers are classified as either core or noncore customers. Core customers are primarily residential and small commercial and industrial customers.

Most core customers purchase natural gas directly from SoCalGas or SDG&E. While core customers are permitted to purchase directly from producers, marketers or brokers, the California Utilities are obligated to provide reliable supplies of natural gas to serve the requirements of their core customers. A substantial portion of SoCalGas’ revenues are from core customers.

Noncore customers at SoCalGas consist primarily of electric generation, wholesale, large commercial and industrial, and enhanced oil recovery customers. A portion of SoCalGas’ noncore customers are non-end-users. SoCalGas’ non-end-users include wholesale customers consisting primarily of other IOUs, including SDG&E, or municipally owned natural gas distribution systems. Noncore customers at SDG&E consist primarily of electric generation and large commercial customers.

Noncore customers are responsible for the procurement of their natural gas requirements, as the regulatory framework does not allow us to recover the actual cost of natural gas procured and delivered to noncore customers.

No single customer accounted for 10 percent or more of SoCalGas’ or SDG&E’s revenues from natural gas operations in 2017, 2016 or 2015.

Demand for natural gas largely depends on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preference, environmental regulations, legislation, California’s energy policy supporting increased electrification and renewable power generation, and the effectiveness of energy efficiency programs. Other external factors such as weather, the price of electricity, the use of hydroelectric power, development of renewable energy resources, development of new natural gas supply sources, demand for natural gas outside the state of California, and general economic conditions, can also result in significant shifts in market price, which may in turn impact demand.

One of the larger sources for natural gas demand is electric generation. Natural gas-fired electric generation within Southern California (and demand for natural gas supplied to such plants) competes with electric power generated throughout the western U.S. Natural gas transported for electric generating plant customers may be affected by the overall demand for electricity, growth in renewable generation (including rooftop solar), the addition of more efficient gas technologies, new energy efficiency initiatives, and the extent that regulatory changes in electric transmission infrastructure investment divert electric generation from the California Utilities’ respective service areas. The demand for natural gas may also fluctuate due to volatility in the demand for electricity due to climate change, weather conditions and other impacts, and the availability of competing supplies of electricity such as hydroelectric generation and other renewable energy sources. Given the significant quantity of natural gas-fired generation, natural gas is the dispatchable fuel of choice to help ensure electric reliability in our California service territories.

The natural gas distribution business is seasonal, and cash provided from operating activities generally is greater during and immediately following the winter heating months. As is prevalent in the industry, but subject to current regulatory limitations, SoCalGas usually injects natural gas into storage during the summer months (April through October), which reduces cash provided by operating activities during this period, and usually withdraws natural gas from storage during the winter months (November through March), which increases cash provided by operating activities, when customer demand is higher.

Natural Gas Procurement and Transportation

At December 31, 2017, SoCalGas’ natural gas facilities include 2,964 miles of transmission and storage pipelines, 50,577 miles of distribution pipelines, 47,779 miles of service pipelines and nine transmission compressor stations, while SDG&E’s natural gas facilities consist of 168 miles of transmission pipelines, 8,928 miles of distribution pipelines, 6,503 miles of service pipelines and one compressor station.

SoCalGas purchases natural gas under short-term and long-term contracts for the California Utilities’ residential and smaller business customers. SoCalGas purchases natural gas from various sources, including from Canada, the U.S. Rockies and the southwestern regions of the U.S. Purchases of natural gas are primarily priced based on published monthly bid-week indices.

To help ensure the delivery of natural gas supplies to its distribution system and to meet the seasonal and annual needs of customers, SoCalGas has firm interstate pipeline capacity contracts that require the payment of fixed reservation charges to reserve firm transportation rights. Pipeline companies, primarily El Paso Natural Gas Company, Transwestern Pipeline Company, PG&E and Kern River Gas Transmission Company, provide transportation services into SoCalGas’ intrastate transmission system for supplies purchased by SoCalGas or its transportation customers from outside of California.

Natural Gas Storage

SoCalGas owns four natural gas storage facilities. These facilities have a combined working gas capacity of 137 Bcf and have over 200 injection, withdrawal and observation wells that provide natural gas storage services for core, noncore and non-end-use customers. SoCalGas’ and SDG&E’s 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. Natural gas withdrawn from storage is important for ensuring service reliability during peak demand periods, including heating needs in the winter, as well as peak electric generation needs in the summer. The Aliso Canyon natural gas storage facility represents 63 percent of SoCalGas’ natural gas storage capacity. SoCalGas discovered a natural gas leak at one of its wells at the Aliso Canyon natural gas storage facility in October 2015, and permanently sealed the well in February 2016. SoCalGas ceased

injecting natural gas into the Aliso Canyon natural gas storage facility on October 25, 2015, pursuant to orders from DOGGR and the Governor of California, and SB 380. Limited withdrawals and injections of natural gas at the Aliso Canyon natural gas storage facility were authorized to recommence in 2017. We discuss the Aliso Canyon natural gas leak in Note 15 of the Notes to Consolidated Financial Statements, in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance” and in “Item 1A. Risk Factors.”

Sempra South American Utilities

Sempra South American Utilities develops, owns and operates, or holds interests in electric transmission, distribution and generation infrastructure through its two utilities, Chilquinta Energía in Chile and Luz del Sur in Peru. It also owns interests in two energy-services companies, Tecnored and Tecsur, that provide electric construction and infrastructure services to Chilquinta Energía and Luz del Sur, respectively, as well as third parties. Tecnored also sells electricity to non-regulated customers.

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 two million in the region of Valparaíso in central Chile, with a service area covering 4,400 square miles. Chilquinta Energía also serves a population of approximately 130,000 in the communities of Parral and Linares in the south-central region of Maule in Chile. Chilquinta Energía is the third largest distributor of electricity in Chile, with close to a 10-percent share of the market.

Customers and Demand. Chilquinta Energía provides electric services through the transmission and distribution of electricity to the following customer classes:

In Chile, customers are classified as regulated and non-regulated customers based on installed capacity. Regulated customers are those whose installed capacity is less than 500 kW. Non-regulated customers are those whose installed capacity is greater than 5,000 kW. Customers with installed capacity between 500 kW and 5,000 kW may choose to be classified as regulated or non-regulated. Non-regulated customers that can buy power from other sources, such as directly from the generator, are classified as tolling customers. Both regulated and non-regulated customers pay transmission and distribution tariffs for the transportation of their electricity through the system. There is no risk of stranded costs for Chilquinta Energía because PPAs with generators are not take-or-pay contracts; rather, Chilquinta Energía only purchases power taken by its customers.

Chilquinta Energía’s system average rate (excluding tolling customers) was $0.164, $0.168 and $0.165 per kWh in 2017, 2016 and 2015, respectively.

Demand for electricity depends on the growth and stability of the Chilean economy, customer growth and preferences, prices, policies and environmental regulations driving the substitution of alternative energy products for wood and coal, legislation and energy policy supporting increased electrification of the public and private transportation sector, and the effectiveness and expansion of energy efficiency programs and distributed generation resources.

The price of electricity can be affected by the growth of renewable power generation, the amount of hydroelectric power, the market price of oil and natural gas, and transmission and distribution service tariffs, which may, in turn, also impact demand for electricity.

Other factors that can affect the demand for electricity include weather and seasonality. Demand for electricity at Chilquinta Energía is higher in the winter months to meet heating load, and tends to decrease during the mild temperatures in the summer months.

Electric Resources. The supply of electric power available to Chilquinta Energía comes from purchased-power contracts currently in place with various suppliers. The supply as of December 31, 2017 was as follows:

CHILQUINTA ENERGÍA – ELECTRIC RESOURCES
	Contract	Net operating
	expiration date	capacity (MW)		% of total
Purchased-power contracts:
Thermal (1)	2023 to 2026	291		62	%
Hydro	2023 to 2036	141		30
Wind/solar	2023 to 2036	32		7
Biomass	2023 to 2036	7		1
Total		471		100	%

⁽¹⁾ Contracts with fuel sources that include natural gas, coal or diesel are collectively referred to as thermal.

Power Generation System. The National Electric System is operated and coordinated by the National Electric Coordinator (Coordinador Eléctrico Nacional). This institution is managed by a Directive Council (Consejo Directivo) formed by five members designated through a public tender. This entity coordinates the operation of the nationwide interconnected electric system.

Transmission System and Access. At December 31, 2017, Chilquinta Energía’s electric facilities include 10,227 miles of distribution lines, 352 miles of transmission lines and 49 substations. Chilquinta Energía also owns a 50-percent interest in Eletrans, which operates a 97-mile, double circuit 220-kV transmission line in the Atacama region of northern Chile, and a 46-mile, double circuit 220-kV transmission line in the Los Rios region of southern Chile.

Transmission lines in Chile are either part of the main transmission system (the national system) or the sub-transmission system (the zonal system). Sub-transmission systems, including those owned by Chilquinta Energía, are comprised of infrastructure that is interconnected to the electricity system to supply non-regulated and regulated end-users located in the distribution service area.

We discuss ongoing transmission line projects at Chilquinta Energía’s joint ventures in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.”

Competition. Chilquinta Energía faces limited competition from the growth in rooftop solar installations, as electricity prices remain competitive and tariffs compensate self-generators only for the commodity component of the energy delivered to the grid. Presently, there are no public programs or incentives promoting the adoption of distributed energy generation.

In addition, the National Electric Coordinator will be tendering a significant number of projects, divided between extension work and new development work, for sub-transmission systems. The new development projects in these tenders will be opened to independent developers, allowing such developers to compete with incumbent utilities for their construction and operation.

Luz del Sur S.A.A.

Sempra South American Utilities owns 83.6 percent of Luz del Sur, an electric distribution utility that serves a population of approximately 4.9 million in the southern zone of metropolitan Lima, Peru, with a service area covering approximately 1,394 square miles. Luz del Sur delivers approximately one-third of all power used in Peru. The remaining shares of Luz del Sur are held by noncontrolling interests and trade on the Lima Stock Exchange (Bolsa de Valores de Lima) under the symbol LUSURC1. The shares are subject to regulation by the Superintendencia del Mercado de Valores (Superintendency of Securities Market).

Customers and Demand. Luz del Sur provides electric services through the generation, transmission and distribution of electricity to the following customer classes:

In Peru, customers are classified as regulated and non-regulated customers based on capacity demand. Regulated customers are those whose capacity demand is less than 200 kW and their energy supply is considered public service. Non-regulated customers, which are free and tolling customers, are those whose capacity demand is greater than 2,500 kW. Customers with capacity demand between 200 kW and 2,500 kW may choose to be classified as regulated or non-regulated. Free customers purchase power directly from a utility and pay the utility a fee for generation, transmission (primary and secondary) and distribution services. Tolling customers purchase power from alternate suppliers and pay only a tolling fee to the utility for secondary transmission and distribution services. Utilities in Peru, including Luz del Sur, generally have PPAs with generators to serve their regulated and free customers’ load. Because the power purchased by Luz del Sur from generators is generally based on take-or-pay contracts, Luz del Sur is exposed to the risk of stranded costs associated with capacity charges, as we discuss in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Factors Influencing Future Performance.”

Luz del Sur’s system average rate (excluding free and tolling customers) was $0.130, $0.122 and $0.117 per kWh in 2017, 2016 and 2015, respectively.

Demand for electricity depends on the stability and growth of the Peruvian economy, customer growth and usage preferences, electricity prices, legislation and energy policy supporting increased electrification within our service territory. The price of electricity can be affected by changes in energy policy, volatility of spot market prices, the amount of hydroelectric power, the market price of oil and natural gas, changes in inflation and foreign exchange rates, new technologies and transmission and distribution service tariffs, which may also impact demand for electricity. Other factors that can affect the demand for electricity include weather and seasonality. Demand for electricity at Luz del Sur is higher in the summer months to meet cooling load, and tends to decrease during the colder temperatures in the winter months.

Electric Resources. The supply of electric power available to Luz del Sur comes from purchased-power contracts currently in place with various suppliers, its own electric generation facility or purchases made on an as-needed basis. This supply as of December 31, 2017 was as follows:

based on guidelines established by the system operator in Peru and historical water flows. Available excess

capacity is sold in the spot market.

Power Generation System. The Sistema Eléctrico Interconectado Nacional (SEIN) is the Peruvian national interconnected system. The OSINERGMIN, in addition to setting tariffs, supervises the bidding processes for energy purchases between distribution companies and generators.

The Committee of Economic Operation of the National Interconnected System (Comité de Operación Económica del Sistema Interconectado Nacional) coordinates the operation and dispatch of electricity of the SEIN.

Transmission System and Access. At December 31, 2017, Luz del Sur’s electric facilities consisted of 13,966 miles of distribution lines, 216 miles of transmission lines and 40 substations. Luz del Sur also owns and operates Santa Teresa, a 100-MW hydroelectric power plant located in the Cusco region of Peru.

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

We discuss ongoing transmission line and substation projects at Luz del Sur in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Influencing Future Performance.”

Competition. While electric distribution companies in Peru are considered natural monopolies, users consuming more than 200 kW are free to choose the company of their preference, including Luz del Sur, to provide them with electric power.

Key Noncash Performance Indicators

Key noncash performance indicators for our South American electric distribution utilities’ operations are customer count and consumption and transmission line losses. Additional noncash performance indicators include goals related to safety, environmental considerations, electric reliability, and regulatory compliance.

Sempra Mexico

Our Sempra Mexico segment includes the operating companies of our subsidiary, IEnova, as well as certain holding companies and risk management activity. IEnova develops, builds and operates energy infrastructure in Mexico, and owns or holds interests in:

Sempra Energy owns 66.4 percent of IEnova, with the remaining shares held by noncontrolling interests and traded on the Mexican Stock Exchange under the symbol IENOVA. The Mexican National Banking and Securities Commission (Comisión Nacional Bancaria y de Valores, or CNBV), regulates the shares, which are registered with the Mexican National Securities Registry (Registro Nacional de Valores) maintained by the CNBV. We discuss IEnova’s noncontrolling interests and its acquisition and divestiture activities in Notes 1 and 3, respectively, of the Notes to Consolidated Financial Statements.

The following table provides information about Sempra Mexico’s facilities, excluding its Ecogas natural gas distribution facilities, that were operational as of December 31, 2017.

Gas Business

Pipelines and Related Assets/Facilities. At December 31, 2017, Sempra Mexico’s assets/facilities consisted of 1,353 miles of natural gas transmission pipelines, 11 compressor stations, 139 miles of ethane pipelines, 118 miles of LPG pipelines and one LPG storage terminal in Mexico. These assets are contracted under long-term, U.S. dollar-based agreements with major industry participants such as the CFE, CENAGAS, PEMEX, Shell, Gazprom, InterGen N.V. and other similar counterparties.

In 2017, our pipeline assets in Mexico had design capacity of approximately 16,501 MMcf per day of natural gas, 204 MMcf per day of ethane gas, 106,000 barrels per day of ethane liquid, 34,000 barrels per day of LPG transmission and 80,000 barrels of LPG storage.

LNG. Sempra Mexico operates its ECA LNG regasification terminal on land it owns in Baja California, Mexico. The ECA LNG regasification terminal is capable of processing 1 Bcf of natural gas per day and generates revenues from reservation and usage fees under terminal capacity agreements and nitrogen injection service 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 LNG & Midstream’s LNG purchase agreement with Tangguh PSC, Sempra Mexico purchases from Sempra LNG & Midstream the LNG delivered to ECA by Tangguh PSC. Sempra Mexico uses the natural gas produced from this LNG and from natural gas purchased in the market or through Sempra LNG & Midstream’s marketing operations to supply a contract for the sale of natural gas to Mexico’s national electric company, the CFE, at prices that are based on the SoCal 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 LNG & Midstream’s natural gas marketing operations.

The LNG business is impacted by worldwide LNG market prices. High LNG prices in markets outside the market in which IEnova’s LNG terminal operates have resulted and could continue to result in lower than expected deliveries of LNG cargoes to the ECA LNG terminal from third parties under existing supply agreements, which could increase costs if IEnova is instead required to obtain LNG in the open market at prevailing prices. Any inability to obtain expected LNG cargoes could also impact IEnova’s ability to maintain the minimum level of LNG required to keep the ECA LNG terminal in operation at the proper temperature. LNG market prices also affect IEnova’s LNG marketing operations, through which IEnova must purchase natural gas in the international market to meet its contractual obligations to deliver natural gas to customers, but which could have an adverse impact on its earnings, which may be mitigated in part by the indemnity payments discussed below.

Sempra Mexico’s LNG marketing operations sell natural gas to the CFE and other customers under supply agreements. Sempra Mexico recognizes the revenue from the sale of natural gas upon transfer of the natural gas via pipelines to the customers at the agreed upon delivery points, and in the case of the CFE, at its thermoelectric power plants.

Sempra LNG & Midstream has an agreement with Sempra Mexico to supply LNG to the ECA LNG terminal. Although the LNG purchase agreement specifies a number of cargoes to be delivered annually, actual cargoes delivered have been significantly lower than the maximum specified under the agreement. As a result, Sempra LNG & Midstream is contractually required to make monthly indemnity payments to Sempra Mexico for failure to deliver the contracted LNG. The revenues from the indemnity payments, along with an amount for profit sharing, allow Sempra Mexico to recover the costs of operating the ECA LNG terminal.

Natural Gas Distribution. Sempra Mexico’s natural gas distribution utility, Ecogas, operates in three separate distribution zones in Mexico with approximately 2,394 miles of pipeline, and had approximately 120,000 customer meters (serving more than 400,000 residential, commercial and industrial consumers) with sales volume of approximately 81 MMcf per day in 2017.

Ecogas relies on affiliates, Sempra LNG & Midstream and SoCalGas, for the supply and transportation of natural gas that it distributes to its customers. If these affiliates fail to perform and IEnova is unable to obtain supplies of natural gas from alternate sources, IEnova could lose customers and sales volume and could also be exposed to commodity price risk and volatility.

Ecogas had been entitled to a 12-year period of exclusivity with respect to each of its three distribution zones in Mexicali, Chihuahua and La Laguna-Durango. As the last of these exclusivity periods expired in 2011, Ecogas could face competition from other distributors of natural gas in all of these distribution zones as other distributors of natural gas are now legally permitted to build natural gas distribution systems and compete with Ecogas for customers.

Power Business

Wind Power Generation. Sempra Mexico develops, invests in and operates renewable energy generation facilities that have long-term PPAs to sell the electricity they generate to its customers, which are generally load serving entities, and industrial and other customers. Load serving entities sell electric service to their end-users and wholesale customers immediately upon receipt of

our power delivery, while industrial and other customers consume the electricity to run their facilities . In 2017, Sempra Mexico had contracted capacity of 330 MW for its ownership share of fully operating wind energy generation facilities.

Natural Gas-Fired Generation. TdM is a 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico that generates revenue from selling electricity and/or resource adequacy to the CAISO and to governmental, public utility and wholesale power marketing entities. It also has an EMA with Sempra LNG & Midstream for energy marketing, scheduling and other related services to support its sales of generated power into the California electricity market. Under the EMA, TdM pays fees to Sempra LNG & Midstream for these revenue-generating services. TdM also purchases fuel from Sempra LNG & Midstream. Sempra Mexico records revenue for the sale of power generated by TdM, and records cost of sales for the purchases of natural gas and energy management services provided by Sempra LNG & Midstream.

In February 2016, management approved a plan to market and sell TdM. As a result, we stopped depreciating the plant and classified the plant as held for sale. We continue to actively pursue the sale of TdM, which we expect to be completed in 2018. We discuss TdM further in Notes 3 and 10 of the Notes to Consolidated Financial Statements.

TdM competes daily with other generating plants that supply power into the California electricity market. Several of the wholesale markets supplied by merchant power plants have experienced significant pricing declines due to excess supply. IEnova manages commodity price risk at TdM by optimizing a mix of forward on-peak energy sales, daily and hourly spot market sales of capacity, energy and ancillary services, and longer-term structured transactions, as well as avoiding short positions.

Demand and Competition

The overall demand for natural gas distribution services increases during the winter months. Conversely, in the power business, the overall demand for electricity is greater during the summer months.

IEnova competes with Mexican and foreign companies for certain new energy infrastructure projects in Mexico and some of its competitors (including but not limited to, public or state-operated companies, their subsidiaries and affiliates) may have better access to capital and greater financial and other resources, which could give them a competitive advantage in bidding for such projects. We discuss Sempra Mexico’s demand and competition further below.

Key Noncash Performance Indicators

Key noncash performance indicators for Sempra Mexico include sales volume, plant or facility availability, capacity utilization and, for its distribution operations, customer count and consumption. Additional noncash performance indicators include obtaining and completing (on time and on budget) major projects, compliance with reliability and regulatory standards, and goals related to safety, environmental considerations and regulatory performance.

Sempra Renewables

Sempra Renewables develops, owns and operates, or holds interests in, solar and wind energy generation facilities in the U.S. that have long-term PPAs to sell the electricity and the related green energy attributes they generate to its customers, which are generally load serving entities. Load serving entities sell electric service to their end-users and wholesale customers immediately upon receipt of our power delivery.

The majority of Sempra Renewables’ wind farm assets earn PTCs based on the number of megawatt hours of electricity they generate. A PTC is a federal subsidy that provides an income tax incentive to wind-energy producers at a flat rate for generating clean energy. 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. For each of the years ended December 31, 2017 , 2016 , and 2015 , PTCs represented a large portion of our wind farm earnings, often exceeding earnings from operations.

Certain of Sempra Renewables’ wind and solar power facilities are held by limited liability companies whose members include financial institutions. These financial institutions are noncontrolling tax equity investors to which earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. We discuss these tax equity arrangements in “Variable Interest Entities” and in “Noncontrolling Interests” in Note 1 of the Notes to Consolidated Financial Statements.

The following table provides information about the Sempra Renewables wind and solar energy generation facilities that were operational as of December 31, 2017 . The generating capacity of these facilities is fully contracted under long-term PPAs for the periods indicated in the table.