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▪	actions and the timing of actions, including decisions, new regulations, and issuances of permits and other authorizations by the CPUC, DOE, DOGGR, FERC, EPA, PHMSA, DPH, states, cities and counties, and other regulatory and governmental bodies in the U.S. and other countries in which we operate;

▪	the timing and success of business development efforts and construction projects, including risks in obtaining or maintaining permits and other authorizations on a timely basis, risks in completing construction projects on schedule and on budget, and risks in obtaining the consent and participation of partners;

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

▪

deviations from regulatory precedent or practice that result in a reallocation of benefits or burdens among shareholders and ratepayers; approvals of proposed settlements or modifications of settlements; and delays in, or disallowance or denial of, regulatory agency authorizations to recover costs in rates from customers (including with respect to amounts associated with the SONGS facility and 2007 wildfires) or regulatory agency approval for projects required to enhance safety and reliability;

▪	the greater degree and prevalence of wildfires in California in recent years and risk that we may be found liable for damages regardless of fault, such as in cases where the doctrine of inverse condemnation applies, and risk that we may not be able to recover any such costs in rates from customers in California;

▪	the risk that rulings by the CPUC such as denying recovery for wildfire damages may raise our cost of capital and materially impair our ability to finance our operations;

▪	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 transmission grid, moratoriums or limitations on the withdrawal or injection of natural gas from or into storage facilities, and equipment failures;

▪	changes in energy markets; volatility in commodity prices; moves to reduce or eliminate reliance on natural gas; and the impact on the value of our investments in natural gas storage and related assets from low natural gas prices, low volatility of natural gas prices and the inability to procure favorable long-term contracts for storage services;

▪	risks posed by actions of third parties who control the operations of our investments, and risks that our partners or counterparties will be unable or unwilling to fulfill their contractual commitments;

▪

weather conditions, natural disasters, accidents, equipment failures, computer system outages, explosions, terrorist attacks and other events that disrupt our operations, damage our facilities and systems, cause the release of GHG, radioactive materials and harmful emissions, cause wildfires and subject us to third-party liability for property damage or personal injuries, fines and penalties, some of which may not be covered by insurance (including costs in excess of applicable policy limits), may be disputed by insurers or may otherwise not be recoverable through regulatory mechanisms or may impact our ability to obtain satisfactory levels of insurance, to the extent that such insurance is available or not prohibitively expensive;

▪	cybersecurity threats to the energy grid, 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;

▪	capital markets and economic conditions, including the availability of credit and the liquidity of our investments; and fluctuations in inflation, interest and currency exchange rates and our ability to effectively hedge the risk of such fluctuations;

▪	the impact of recent federal tax reform and uncertainty as to how it may be applied, and our ability to mitigate any adverse impacts;

▪	actions by rating agencies to downgrade our credit ratings or those of our subsidiaries or to place those ratings on negative outlook;

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▪	changes in foreign and domestic trade policies and laws, including border tariffs, and revisions to international trade agreements, such as NAFTA, that make us less competitive or impair our ability to resolve trade disputes;

▪	the ability to win competitively bid infrastructure projects against a number of strong and aggressive competitors;

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

▪	the impact on reliability of SDG&E’s electric transmission and distribution system due to increased amount and variability of power supply from renewable energy sources;

▪

the impact on competitive customer rates due to 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 and from possible departing retail load resulting from customers transferring to DA and CCA or other forms of distributed and local power generation and the potential risk of nonrecovery for stranded assets and contractual obligations; and

▪	other uncertainties, some of which may be difficult to predict and are beyond our control.

▪	the risk that Sempra Energy, EFH or Oncor may be unable to satisfy all closing conditions including obtaining governmental and regulatory approvals required for the Merger, or that required governmental and regulatory approvals may delay the Merger or result in the imposition of conditions that could cause the parties to abandon the Merger or be onerous to Sempra Energy;

▪	the risk that the Merger may not be completed for other reasons, or may not be completed on the terms or timing currently contemplated;

▪	the risk that the anticipated benefits from the Merger may not be fully realized or may take longer to realize than expected and that liabilities that survive the bankruptcy will be greater than we anticipate;

▪	the risk that Sempra Energy may be unable to obtain additional permanent equity financing for the Merger on favorable terms;

▪	the risk that indebtedness Sempra Energy incurs in connection with the Merger may make it more difficult for Sempra Energy to repay or refinance its debt or take other actions, which may decrease business flexibility and increase borrowing costs;

▪	the diversion of management time and attention to Merger-related issues and related costs, whether or not the Merger is completed, as well as disruptions to our business; and

▪

the risk that Oncor will eliminate or reduce its quarterly dividends due to its requirement to meet and maintain its new regulatory capital structure, or because any of the three major rating agencies rates Oncor’s senior secured debt securities below BBB (or the equivalent) or Oncor’s independent directors or a minority member director determine that it is in the best interest of Oncor to retain such amounts to meet future capital expenditures.

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▪	Sempra Energy and its consolidated entities

▪	SDG&E and its consolidated VIE

▪	SoCalGas

▪	U.S. and South American regulated utilities

▪	U.S. and Mexican energy infrastructure

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(1)	Includes intercompany sales.

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(1)	Excludes approximately 114 MW of battery storage owned (including 70 MW pending CPUC approval) and approximately 13.5 MW of battery storage contracted (all pending CPUC approval).

(2)	SDG&E owns and operates four natural gas-fired power plants, three of which are in California and one of which is in Nevada.

(3)	Includes Otay Mesa VIE.

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(1)	Includes intercompany sales.

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(1)	Santa Teresa has a nameplate capacity of 100 MW with an associated firm capacity estimated at 61 MW

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

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▪	natural gas transmission pipelines

▪	LPG and ethane systems

▪	a natural gas distribution utility

▪	electric generation facilities, including wind, solar and a natural gas-fired power plant (presently held for sale)

▪	a terminal for the import of LNG

▪	a terminal for the storage of LPG

▪	marine and inland terminal projects for the receipt, storage and delivery of liquid fuels

▪	marketing operations for the purchase of LNG and the purchase and sale of natural gas

(1)	Sempra Mexico has a 50-percent interest in each of these facilities and accounts for them as equity method investments. The information presented herein represents the full nameplate capacity.

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(1)	If placed in service in phases, indicates the year the first phase went into service.

(2)	Represents facilities that we own through tax equity arrangements. We consolidate these entities and report noncontrolling interests.

(3)	Total expected generating capacity for Great Valley Solar is 200 MW, of which three phases totaling 100 MW went into service in 2017; we expect the remaining 100-MW phase to be in service in the first half of 2018.

(4)	Sempra Renewables has a 50-percent interest in each of these facilities and accounts for them as equity method investments. The generating capacity shown herein represents Sempra Renewables’ share only.

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▪	a terminal in the U.S. for the import and export of LNG and sale of natural gas

▪	natural gas pipelines and storage facilities

▪	marketing operations

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

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

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

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

▪	existing LNG tankage and berths.

▪

Bay Gas is a facility located 40 miles north of Mobile, Alabama, that provides underground storage (20 Bcf of operational working natural gas storage capacity) and delivery of natural gas. Sempra LNG & Midstream owns approximately 91 percent of the facility. 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 is an underground salt dome with 22 Bcf of operational working natural gas storage capacity located 45 miles southeast of Jackson, Mississippi. It has access to natural gas from shale basins of East Texas and Louisiana, traditional Gulf Coast supplies and LNG, with multiple interconnections to serve the Southeast and Northeast regions.

▪

Liberty Gas Storage, LLC owns a 77-percent interest in LA Storage, a salt cavern development project in Cameron Parish, Louisiana, and ProLiance Transportation LLC owns the remaining 23 percent. The project’s location provides access to several LNG facilities in the area and could be positioned to support LNG export from various liquefaction terminals. Future development will require approval of a new construction permit by the FERC, if anticipated cash flows support further investment. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage pipeline, that is not currently contracted.

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

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

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

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

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

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

▪	sponsors alternative-energy research and development projects;

▪	promotes energy conservation programs to reduce demand within the state of California for electricity and natural gas;

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

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

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▪	Sempra Renewables and Sempra LNG & Midstream: market-based for wholesale electricity sales

▪	Sempra LNG & Midstream: cost-based for the transportation of natural gas

▪	Sempra LNG & Midstream: market-based for the storage of natural gas, as well as the purchase and sale of LNG and natural gas

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▪	operational incentives (electric reliability)

▪	energy efficiency

▪	energy efficiency

▪	natural gas procurement

▪	unbundled natural gas storage and system operator hub services

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(1)	Ages are as of February 27, 2018.

(2)	Mr. Davis will retire as of March 1, 2018.

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(1)	Ages are as of February 27, 2018.

(2)	Mr. Baker will retire as of May 1, 2018.

(3)	Mr. Schavrien will retire as of April 1, 2018.

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(1)	Ages are as of February 27, 2018.

(2)	Mr. Baker will retire as of May 1, 2018.

(3)	Mr. Schavrien will retire as of April 1, 2018.

(4)	Mr. Snyder will retire as of June 1, 2018.

(1)	Excludes employees of variable interest entities as defined by U.S. GAAP.

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▪	Sempra Energy – www.sempra.com

▪	SDG&E – www.sdge.com

▪	SoCalGas – www.socalgas.com

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▪	natural gas, propane and ethane pipelines, storage and compressor facilities;

▪	electric transmission and distribution;

▪	power generation plants, including renewable energy and natural gas-fired generation;

▪	marine and inland liquid fuels, LNG and LPG terminals and storage;

▪	nuclear fuel and nuclear waste storage facilities; and

▪	nuclear power facilities (currently being decommissioned).

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▪	Sempra Utilities – Technologies that could change the utilization of natural gas distribution and electric generation, transmission and distribution assets, including:

◦	the expanded cost-effective utilization of distributed generation (e.g., rooftop solar and community solar projects), and

◦	energy storage technology.

▪	Sempra Infrastructure

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

◦	At Sempra LNG & Midstream, technological advances could reduce the demand for natural gas. These technologies include cost-effective batteries for renewable electricity generation, economic improvements to gas-to-liquids conversion processes, and advances in alternative fuels and other alternative energy sources.

▪	conditions of service;

▪	capital structure;

▪	rates of return;

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▪	rates of depreciation;

▪	long-term resource procurement; and

▪	sales of securities.

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▪	the rates charged to our customers;

▪	our ability to site and construct new facilities;

▪	our ability to purchase or construct generating facilities;

▪	our ability to shut down power for safety reasons, including potentially dangerous wildfire conditions;

▪	general safety;

▪	accounting and income tax matters, including changes in tax law;

▪	transactions between affiliates;

▪	the installation of environmental emission controls equipment;

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

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

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

▪	the amount of costs associated with these and other operations that may be recovered from customers.

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▪	reductions in short-lived climate pollutants and other greenhouse gases be at least equivalent to the amount of the emissions from the Leak,

▪	a 20-year global warming potential be used in deriving the amount of reductions required (rather than the 100-year term the CARB and other state and federal agencies use in regulating emissions), and

▪	all of the mitigation occur in California over the next five to ten years without the use of allowances or offsets.

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

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

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

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

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▪	weather conditions

▪	seasonality

▪	changes in supply and demand

▪	transmission or transportation constraints or inefficiencies

▪	availability of competitively priced alternative energy sources

▪	commodity production levels

▪	actions by oil and natural gas producing nations or organizations affecting the global supply of crude oil and natural gas

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

▪	natural disasters, wars, embargoes and other catastrophic events

▪	expropriation of assets by foreign countries

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▪	negotiation of satisfactory EPC agreements

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

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

▪	timely implementation and satisfactory completion of construction

▪	obtaining adequate and reasonably priced financing for the project

▪	unforeseen engineering problems

▪	construction delays and contractor performance shortfalls

▪	work stoppages

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

▪	equipment unavailability or delay and cost increases

▪	adverse weather conditions

▪	environmental and geological conditions

▪	litigation

▪	unsettled property rights

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

▪	supply natural gas to our gas storage and electric generation facilities, and

▪	provide retail energy services to customers.

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

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

▪	adverse changes in market conditions and inadequate enforcement of regulations

▪	high rates of inflation

▪	volatility in exchange rates between the U.S. dollar and currencies of the countries in which we operate, as we discuss below

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

▪	changes in government policies or personnel

▪	trade restrictions

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

▪	permitting and regulatory compliance

▪	changes in labor supply and labor relations

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

▪	expropriation of assets

▪	destruction of property or assets

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

▪	general political, social, economic and business conditions

▪	compliance with the Foreign Corrupt Practices Act and similar laws

▪	valuation of goodwill

▪	theft of assets

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▪	make it more difficult and/or costly for us to pay or refinance our debts as they become due, particularly during adverse economic and industry conditions, because a decrease in revenues or increase in costs could cause cash flow from operations to be insufficient to make scheduled debt service payments;

▪	limit our flexibility to pursue other strategic opportunities or react to changes in our business and the industry sectors in which we operate and, consequently, put us at a competitive disadvantage to our competitors that have less debt;

▪

require a substantial portion of our available cash to be used for debt service payments, thereby reducing the availability of our cash to fund working capital, capital expenditures, development projects, acquisitions, dividend payments and other general corporate purposes, which could hinder our prospects for growth and the market price of our common stock, preferred stock and debt securities, among other things;

▪	result in a downgrade in the credit ratings on our indebtedness (including as discussed above under “Risks Related to Sempra Energy – Certain credit rating agencies may downgrade our credit ratings or place those ratings on negative outlook, which may

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▪	make it more difficult for us to raise capital to fund working capital, make capital expenditures, pay dividends, pursue strategic initiatives or for other purposes;

▪	result in higher interest expense in the event of increases in interest rates on our current or future borrowings subject to variable rates of interest;

▪	require that additional materially adverse terms, conditions or covenants be placed on us under our debt instruments, which covenants might include, for example, limitations on additional borrowings; and

▪	result in specific restrictions on uses of our assets, as well as prohibitions or limitations on our ability to create liens, pay dividends, receive distributions from our subsidiaries, redeem or repurchase our stock or make investments, any of which could hinder our access to capital markets and limit or delay our ability to carry out our capital expenditure program.

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▪

Following consummation of the Merger, the board of directors of Oncor will consist of thirteen members, seven of which will be independent directors in all material respects under the rules of the New York Stock Exchange in relation to Sempra Energy and its subsidiaries and affiliated entities and any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings (and those directors must have no material relationship with Sempra Energy or its affiliates, or any other entity with a direct or indirect ownership interest in Oncor or Oncor Holdings, at the time of the Merger or within the previous 10 years), two of which will be designated by Sempra Energy, two of which will be appointed by Oncor’s minority owner, TTI, which is an investment vehicle owned by third parties unaffiliated with EFH and Sempra Energy and that owns approximately 19.75 percent of the outstanding membership interests in Oncor, and two of which will be members of Oncor management, initially Robert S. Shapard and E. Allen Nye, Jr., who no later than the closing of the Merger will be the Chair of the Oncor board and chief executive officer of Oncor, respectively. In addition, Oncor Holdings will also continue to have a majority of independent directors following the consummation of the Merger;

▪	If the credit rating on Oncor’s senior secured debt by any of the three major rating agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT;

▪	We have agreed to make, within 60 days after the Merger, our proportionate share of the aggregate equity investment in Oncor in an amount necessary for Oncor to achieve a capital structure consisting of 57.5 percent long-term debt and 42.5 percent equity, as calculated for regulatory purposes;

▪

Oncor may not pay dividends or make any other distributions (except for contractual tax payments) to its owners, including Sempra Energy, if a majority of its independent directors or a minority member director determines that it is in the best interests of Oncor to retain such amounts to meet expected future requirements (including continuing compliance with its debt-to-equity ratio required by the PUCT described above);

▪	Certain transactions, including certain mergers and sales of substantially all assets, changes to the dividend policy and declarations of bankruptcy and liquidation, require the approval of all, or in certain circumstances a majority, of the independent directors of Oncor and at least one, or in certain circumstances both, of the directors appointed by Oncor’s minority owner, TTI; and

▪	There must be maintained certain “separateness measures” that reinforce the financial separation of Oncor from EFH and EFH’s owners, such as a prohibition on Oncor providing guarantees or security for debt of EFH or Sempra Energy.

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▪	they are unable to establish, maintain or unwind their hedge position with respect to the forward sale agreements;

▪

they determine that they are unable to, or it is commercially impracticable for them to, continue to borrow a number of shares of our common stock equal to the number of shares of our common stock underlying the forward sale agreements or that, with respect to borrowing such number of shares of our common stock, they would incur a rate that is greater than the borrow cost specified in the forward sale agreements, subject to a prior notice requirement;

▪	we declare or pay cash dividends on shares of our common stock in an amount in excess of amounts, or at a time before, those prescribed by the forward sale agreements or declare or pay certain other types of dividends or distributions on shares of our common stock;

▪	an event is announced that, if consummated, would result in an extraordinary event (including certain mergers and tender offers, our nationalization, our insolvency and the delisting of the shares of our common stock);

▪	an ownership event (as such term is defined in the forward sale agreements) occurs; or

▪	certain other events of default, termination events or other specified events occur, including, among other things, a change in law.

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(1)

Consists of 195,801 options to purchase shares of our common stock, all of which were granted at an exercise price equal to 100 percent of the grant date fair market value of the shares subject to the option, 1,701,617 performance-based RSUs and 285,895 service-based RSUs. Each performance-based RSU represents the right to receive from zero to 1.5 shares (2.0 shares for awards granted during or after 2014) of our common stock if applicable performance conditions are satisfied. The 2,183,313 shares also include awards granted under two previously shareholder-approved long-term incentive plans (Predecessor Plans). No new awards may be granted under these Predecessor Plans.

(2)	Represents only the weighted-average exercise price of the 195,801 outstanding options to purchase shares of common stock.

(3)

The number of shares available for future issuance is increased by the number of shares to which the participant would otherwise be entitled that are withheld or surrendered to satisfy the exercise price or to satisfy tax withholding obligations relating to any plan awards, and is also increased by the number of shares subject to awards that expire or are forfeited, canceled or otherwise terminated without the issuance of shares.

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(1)	Includes capital lease obligations.

(2)	Includes long-term debt due within one year and current portion of capital lease obligations.

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(1)	Includes capital lease obligations.

(2)	Includes long-term debt due within one year and current portion of capital lease obligations.

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▪	In June 2017, Sempra Mexico reduced the carrying value of TdM by recognizing an impairment charge ($47 million earnings impact).

▪	In July 2017, Sempra Renewables acquired the Great Valley Solar Project located in Fresno County, California for initial cash consideration of $124 million, with an expected investment totaling $375 million to $425 million once fully constructed.

▪	In August 2017, Sempra Energy entered into a Merger Agreement to acquire EFH, the indirect owner of an 80.03-percent interest in Oncor, for the Merger Consideration of $9.45 billion in cash. We expect the Merger to close in the first half of 2018.

▪	In September 2017, SDG&E recognized a charge for the write-off of a regulatory asset associated with wildfire costs ($208 million earnings impact).

▪	In November 2017, IEnova purchased the remaining 50-percent interest in DEN, which owns a 50-percent interest in the Los Ramones Norte pipeline through TAG, for total consideration of $165 million, plus the assumption of $96 million of short-term debt.

▪	In December 2017, Cameron LNG JV entered into a settlement agreement with its EPC contractor for the Cameron LNG JV liquefaction facility. We discuss the agreement below in “Factors Influencing Future Performance – Cameron LNG JV Three-Train Liquefaction Project.”

▪	In December 2017, the TCJA was signed into law, resulting in an $870 million increase in income tax expense at Sempra Energy Consolidated in the fourth quarter of 2017 from the effects of the TCJA. We discuss the impact of the TCJA below in “Changes in Revenues, Costs and Earnings – Income Taxes” and in Note 6 of the Notes to Consolidated Financial Statements.

▪

SoCalGas has resumed injections and withdrawals, on a limited basis, at its Aliso Canyon natural gas storage facility. As of December 31, 2017, SoCalGas’ cost estimate is $913 million related to the Aliso Canyon natural gas storage facility gas leak, which includes $887 million of costs recovered or probable of recovery from insurance, as we discuss in Note 15 of the Notes to Consolidated Financial Statements.

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(1)	After preferred dividends.

(2)	Includes $1,165 million income tax expense from the effects of the TCJA in 2017, and after-tax interest expense ($170 million in 2017, $169 million in 2016 and $157 million in 2015), intercompany eliminations recorded in consolidation and certain corporate costs.

▪	$208 million charge for the write-off of a regulatory asset associated with wildfire costs, which we discuss in Note 15 of the Notes to Consolidated Financial Statements;

▪	$28 million unfavorable impact from the remeasurement of certain U.S. federal deferred income tax assets from 35 percent to 21 percent as a result of the TCJA; and

▪	$7 million income tax benefit in 2016 associated with excess tax benefits related to share-based compensation; offset by

▪	$31 million of charges in 2016 associated with 2012-2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD;

▪	$27 million higher CPUC base operating margin authorized for 2017 and lower non-refundable operating costs;

▪	$17 million increase in AFUDC related to equity; and

▪	$8 million favorable impact in 2017 from the resolution of prior years’ income tax items.

▪	$31 million of charges associated with 2012-2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD;

▪	$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 pursuant to an amended settlement agreement approved by the CPUC in 2014;

▪	$9 million lower favorable impact in 2016 related to the resolution of prior years’ income tax items; and

▪	$7 million lower earnings from electric transmission primarily due to lower formulaic revenues associated with lower borrowing costs; offset by

▪	$23 million higher CPUC base operating margin authorized for 2016, including lower generation major maintenance costs, and lower non-refundable operating costs;

▪	$9 million increase in AFUDC related to equity;

▪	$7 million income tax benefit associated with excess tax benefits related to share-based compensation; and

▪	$7 million lower net interest expense.

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▪	$49 million of charges in 2016 associated with 2012-2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD;

▪	$16 million higher earnings associated with the PSEP and advanced metering assets; and

▪	$13 million impairment of assets in 2016 related to the Southern Gas System Reliability Project (also referred to as the North-South Pipeline); offset by

▪	$20 million for Aliso Canyon litigation reserves; and

▪	$4 million income tax benefit in 2016 associated with excess tax benefits related to share-based compensation.

▪	$49 million of charges associated with 2012-2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD;

▪	$16 million charge associated with tracking the 2016 income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD;

▪	$16 million lower favorable impact in 2016 related to the resolution of prior years’ income tax items;

▪	$13 million impairment of assets related to the Southern Gas System Reliability project;

▪	$13 million lower regulatory awards;

▪	$11 million of earnings in 2015 from a CPUC-approved retroactive increase in authorized GRC revenue requirement for years 2012 through 2014 due to increased rate base; and

▪	$8 million higher net interest expense primarily due to debt issuances in the second quarter of 2015; offset by

▪	$27 million higher CPUC base operating margin authorized for 2016, and lower non-refundable operating costs; and

▪	$23 million higher earnings associated with the PSEP and advanced metering assets.

▪	$16 million lower income tax expense, including $17 million income tax expense in 2016 related to Peruvian tax reform, as we discuss below in “Changes in Revenues, Costs and Earnings – Income Taxes;”

▪	$8 million higher earnings from operations primarily due to an increase in rates and lower operating expenses at Luz del Sur; and

▪	$6 million higher earnings from foreign currency translation effects.

▪	$15 million higher income tax expense, including $17 million related to Peruvian tax reform;

▪	$9 million lower earnings from foreign currency translation effects;

▪	$7 million business interruption insurance proceeds in 2015 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; and

▪	$3 million lower capitalized interest primarily due to completion of construction of the Santa Teresa hydroelectric power plant in 2015; offset by

▪	$10 million higher earnings from operations mainly due to the start of operations of the Santa Teresa hydroelectric power plant in September 2015.

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▪	$432 million noncash gain in 2016 associated with the remeasurement of our equity interest in IEnova Pipelines (formerly known as GdC);

▪

$36 million favorable impact in 2016 due to $55 million favorable foreign currency and inflation effects, offset by a $19 million loss from foreign currency derivatives, which we use to hedge Sempra Mexico’s foreign currency exposure from its controlling interest in IEnova, compared to $35 million unfavorable impact in 2017 due to $84 million unfavorable foreign currency and inflation effects, offset by a $49 million gain from foreign currency derivatives. We discuss these effects below in “Impact of Foreign Currency and Inflation Rate on Results of Operations;”

▪	$28 million higher income tax expense in 2017 mainly related to a deferred income tax liability on an outside basis difference in joint venture investments; and

▪	$28 million higher interest expense, including $19 million at Ventika and $8 million at IEnova Pipelines related to debt assumed in their respective acquisitions; offset by

▪	$98 million higher pipeline operational earnings, primarily attributable to the increase in ownership in IEnova Pipelines from 50 percent to 100 percent in September 2016 and from other pipeline assets placed in service;

▪	$73 million earnings attributable to noncontrolling interests at IEnova in 2017, compared to $133 million in 2016, as we discuss below in “Changes in Revenues, Costs and Earnings – Earnings Attributable to Noncontrolling Interests;”

▪	$71 million impairment in 2017 of TdM assets held for sale, net of a $12 million income tax benefit that has been fully reserved, compared to a $111 million impairment in 2016 of such assets;

▪	$34 million higher operational earnings in 2017 from Sempra Mexico’s renewables business, primarily due to Ventika, which we acquired in December 2016; and

▪	$8 million tax benefit in 2017 from a reduction to the outside basis deferred tax liability on our investment in the TdM natural gas-fired power plant that is held for sale, compared to an $8 million tax expense in 2016.

▪	$432 million noncash gain associated with the remeasurement of our 50-percent equity interest in IEnova Pipelines;

▪	$20 million incremental earnings from the increase in our ownership interest in IEnova Pipelines from 50 percent to 100 percent in September 2016; and

▪	$8 million increase in earnings from our natural gas local distribution company mainly associated with new distribution rates; offset by

▪	$111 million impairment of TdM assets held for sale;

▪	$80 million increase in earnings attributable to noncontrolling interests at IEnova;

▪	$36 million favorable impact in 2016, compared to $49 million favorable impact in 2015 due primarily to transactional effects from foreign currency and inflation, including amounts in equity earnings from our joint ventures; and

▪	$8 million deferred income tax expense on our investment in TdM as a result of management’s decision to hold the asset for sale.

▪	$192 million favorable impact from the remeasurement of U.S. federal deferred income tax liabilities from 35 percent to 21 percent as a result of the TCJA; and

▪	$14 million higher earnings from our solar tax equity investments, including $19 million of higher pretax losses attributed to solar tax equity investors reflected in noncontrolling interests, offset by $7 million associated income taxes; offset by

▪	$6 million higher general and administrative and development costs.

▪	$12 million lower solar ITCs from projects placed in service in 2015; and

▪	$5 million gain in 2015 from the sale of the Rosamond Solar development project; offset by

▪	$8 million higher earnings from increased production at our wind and solar assets.

▪	$133 million favorable impact from the remeasurement of U.S. federal deferred income tax liabilities from 35 percent to 21 percent as a result of the TCJA;

▪	$123 million loss in 2016 on permanent release of certain pipeline capacity;

▪	$40 million improved results in 2017 due to unfavorable results from midstream activities, including LNG operations, in 2016;

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▪	$34 million settlement proceeds received from a breach of contract claim against a counterparty in bankruptcy court, of which $28 million was related to the charge in 2016 from the permanent release of certain pipeline capacity, as we discuss in Note 15 of the Notes to Consolidated Financial Statements; and

▪	$27 million impairment charge in 2016 related to our investment in Rockies Express; offset by

▪	$78 million gain on the sale of EnergySouth in September 2016, net of related expenses;

▪	$11 million lower equity earnings resulting from the sale of our investment in Rockies Express in May 2016; and

▪	$6 million lower earnings in 2017 due to the sale of EnergySouth in September 2016.

▪	$123 million loss on permanent release of pipeline capacity;

▪	$36 million gain in 2015 on the sale of the remaining 625-MW block of the Mesquite Power plant, net of related expenses;

▪	$36 million lower equity earnings resulting from the sale of our investment in Rockies Express;

▪	$27 million impairment charge related to our investment in Rockies Express; and

▪	$15 million lower results primarily driven by changes in natural gas prices; offset by

▪	$78 million gain on the sale of EnergySouth, net of related expenses.

▪	$1,147 million income tax expense in 2017 compared to a $54 million tax benefit in 2016, primarily due to:

◦	$1,165 million unfavorable impact from the TCJA, including:

▪	$477 million from the remeasurement of U.S. federal deferred income tax balances from 35 percent to 21 percent,

▪	$360 million U.S. state and non-U.S. withholding tax expense on our expected repatriation of foreign undistributed earnings estimated for deemed repatriation, and

▪	$328 million of U.S. federal deemed repatriation tax,

◦	$20 million U.S. income tax benefit in 2016 as a result of a change in planned repatriation of earnings, as we discuss below in “Changes in Revenues, Costs and Earnings – Income Taxes,” and

◦	$17 million income tax benefit in 2016 associated with excess tax benefits related to share-based compensation; and

▪	$20 million of costs in 2017 associated with foreign currency derivatives; offset by

▪	$31 million higher investment gains on dedicated assets in support of our executive retirement and deferred compensation plans, net of an increase in deferred compensation expense associated with those investments.

▪	$32 million higher income tax benefits, including:

◦	$40 million lower U.S. tax expense in 2016 as a result of a change in planned repatriation, and

◦	$17 million income tax benefit associated with excess tax benefits related to share-based compensation, offset by

◦	$14 million income tax benefits in 2015 associated with the favorable resolution of prior years’ income tax items, and

◦	$7 million income tax benefits in 2015 from a decrease in state valuation allowances; and

▪	$10 million higher investment gains in 2016 on dedicated assets in support of our executive retirement and deferred compensation plans, net of an increase in deferred compensation expense associated with those investments; offset by

▪	$10 million higher net interest expense.

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(1)	Income taxes were calculated based on applicable statutory tax rates, except for adjustments that are solely income tax. Income taxes associated with TdM were calculated based on the applicable statutory tax rate, including translation from historic to current exchange rates. An income tax benefit of $12 million associated with the 2017 TdM impairment has been fully reserved.

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(1)	Income taxes were calculated based on applicable statutory tax rates, except for adjustments that are solely income tax.

(1)	Income taxes were calculated based on applicable statutory tax rates, except for adjustments that are solely income tax.

▪	SDG&E

▪	Sempra South American Utilities’ Chilquinta Energía and Luz del Sur

▪	SDG&E

▪	SoCalGas

▪	Sempra Mexico’s Ecogas

▪	Sempra LNG & Midstream’s Mobile Gas and Willmut Gas (prior to the sale of EnergySouth on September 12, 2016)

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▪	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.

▪

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’ GCIM 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 “Item 1. Business.”

▪	also permits the California Utilities to recover certain expenses for programs authorized by the CPUC, or “refundable programs.”

▪	$181 million increase at SDG&E, including:

◦	$106 million higher cost of electric fuel and purchased power, which we discuss below,

◦	$52 million of charges in 2016 associated with 2012-2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD,

◦	$52 million increase in 2017 due to an increase in rates permitted under the attrition mechanism in the 2016 GRC FD, and

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◦	$31 million higher authorized revenues from electric transmission, offset by

◦	$50 million charge in 2017 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD,

◦	$9 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in O&M, and

◦	$5 million in 2016 to reduce estimated 2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD to actual deductions taken on the 2015 tax return; and

▪	$23 million increase at Sempra South American Utilities, including:

◦	$56 million due to foreign currency exchange rate effects, and

◦	$44 million due to higher rates at Luz del Sur, offset by lower rates at Chilquinta Energía, offset by

◦	$75 million lower volumes at Luz del Sur, primarily due to the migration of regulated and non-regulated customers to tolling customers, who pay only a tolling fee.

▪	$35 million increase at SDG&E, including:

◦	$37 million higher authorized revenue in the 2016 GRC FD,

◦	$36 million higher cost of electric fuel and purchased power, which we discuss below,

◦	$31 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in O&M, and

◦	$5 million to reduce estimated 2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD to actual deductions taken on the 2015 tax return, offset by

◦	$52 million of charges associated with 2012-2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD; and

▪	$16 million increase at Sempra South American Utilities, including:

◦	$117 million due to higher rates at Luz del Sur and Chilquinta Energía primarily due to $81 million of increased costs passed through to customers, offset by

◦	$69 million due to foreign currency exchange rate effects,

◦	$24 million lower volumes at Luz del Sur, net of the effects of higher revenues from the Santa Teresa hydroelectric power plant, which began commercial operations in September 2015, and

◦	$9 million business interruption insurance proceeds in 2015.

▪	$106 million increase at SDG&E, primarily due to an increase in the cost of purchased power due to higher natural gas prices, an increase from the incremental purchase of renewable energy at higher prices and an additional capacity contract; offset by

▪	$13 million decrease at Sempra South American Utilities primarily due to:

◦	$48 million lower volumes at Luz del Sur, offset by

◦	$38 million due to foreign currency exchange rate effects.

▪	$36 million increase at SDG&E, including:

◦	an increase from the incremental purchase of renewable energy at higher prices, offset by

◦	a decrease in cost of purchased power due to declining natural gas prices, and

◦	a decrease in consumption due to increased rooftop solar installations, weather impacts and energy efficiency initiatives; and

▪	$16 million increase at Sempra South American Utilities primarily due to:

◦	$81 million of increased costs passed through to customers, offset by

◦	$48 million due to foreign currency exchange rate effects, and

◦	$28 million lower volumes at Luz del Sur, net of the effects of increased costs at the Santa Teresa hydroelectric power plant.

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▪	$314 million increase at SoCalGas, which included

◦	$134 million increase in cost of natural gas sold, which we discuss below,

◦	$83 million of charges in 2016 associated with 2012-2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD,

◦	$57 million increase due to 2017 attrition,

◦	$49 million higher revenues primarily associated with the PSEP,

◦	$10 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in O&M, and

◦	$5 million GCIM award approved by the CPUC in January 2017, offset by

◦	$19 million in 2016 to reduce estimated 2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD to actual deductions taken on the 2015 tax return, and

◦	$14 million charge in 2017 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD;

▪	$42 million increase at SDG&E, which included

◦	$37 million increase in cost of natural gas sold, which we discuss below, and

◦	$21 million higher revenues primarily associated with the PSEP, offset by

◦	$13 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in O&M; and

▪	$22 million increase at Sempra Mexico primarily due to higher natural gas prices and higher rates for distribution at Ecogas; offset by

▪	$68 million decrease at Sempra LNG & Midstream due to the sale of EnergySouth in September 2016.

▪	$35 million decrease at Sempra LNG & Midstream primarily due to the sale of EnergySouth in September 2016;

▪	$18 million decrease at SoCalGas, which included

◦	$83 million of charges associated with 2012-2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD,

◦	$30 million decrease in cost of natural gas sold, due to $38 million from lower average prices offset by $8 million from higher volume,

◦	$27 million charge associated with tracking the 2016 income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD,

◦	$21 million lower regulatory awards, and

◦	$19 million increase in 2015 from a CPUC-approved retroactive increase in authorized GRC revenue requirement for years 2012 through 2014 due to increased rate base, offset by

◦	$56 million higher revenues primarily associated with the PSEP and advanced metering assets,

◦	$52 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in O&M,

◦	$49 million higher authorized revenue in the 2016 GRC FD, and

◦	$19 million to reduce estimated 2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD to actual deductions taken on the 2015 tax return; and

▪	$1 million decrease at SDG&E, which included

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◦	$26 million decrease in cost of natural gas sold, due to $34 million from lower average prices offset by $8 million from higher volume, offset by

◦	$9 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in O&M, and

◦	$8 million higher revenues primarily associated with the PSEP.

▪	$134 million increase at SoCalGas, due to $114 million from higher average prices and $20 million from higher volumes driven by weather;

▪	$37 million increase at SDG&E primarily due to higher average prices; and

▪	$18 million increase at Sempra Mexico, primarily due to higher natural gas prices at Ecogas; offset by

▪	$49 million primarily from higher elimination of intercompany costs at Sempra Mexico.

(1)	Includes eliminations of intercompany activity.

(2)	Excludes depreciation and amortization, which are presented separately on the Sempra Energy Consolidated Statements of Operations.

▪	$449 million increase at Sempra Mexico primarily due to:

◦	$293 million from the acquisition of the remaining 50-percent interest in IEnova Pipelines in September 2016 and from other pipeline assets placed in service,

◦	$96 million from the acquisition of Ventika in December 2016,

◦	$30 million higher revenues primarily due to higher natural gas prices and customer base in its gas business, and

◦	$28 million increase at TdM due to higher power prices and volumes;

▪	$100 million increase at Sempra LNG & Midstream, which included

◦	$51 million primarily from natural gas marketing activities, including an increase in sales of natural gas, and from changes in natural gas prices,

◦	$29 million from higher natural gas and LNG sales to Sempra Mexico primarily due to higher natural gas prices,

◦	$12 million from non-delivery of LNG cargoes due to higher natural gas prices, and

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◦	$10 million attributable to Cameron Interstate Pipeline; and

▪	$60 million increase at Sempra Renewables primarily due to solar and wind assets placed in service during 2016; offset by

▪	$88 million primarily from higher intercompany eliminations associated with sales between Sempra LNG & Midstream and Sempra Mexico.

▪	$110 million decrease at Sempra LNG & Midstream, which included

◦	$63 million primarily driven by changes in natural gas prices and lower volumes,

◦	$34 million lower power revenues due to the sale of the second block of Mesquite Power in April 2015, and

◦	$13 million from lower natural gas sales to Sempra Mexico; offset by

▪	$49 million higher revenues at Sempra Mexico primarily due to:

◦	$82 million due to the acquisition of the remaining 50-percent interest in IEnova Pipelines in September 2016, offset by

◦	$30 million lower power volumes at the TdM power plant; and

▪	$12 million primarily from lower intercompany eliminations associated with sales between Sempra LNG & Midstream and Sempra Mexico.

▪	$52 million increase at Sempra Mexico primarily due to higher natural gas costs and customer base in its gas business; and

▪	$45 million increase at Sempra LNG & Midstream primarily due to higher natural gas costs; offset by

▪	$42 million from higher intercompany eliminations of costs associated with sales between Sempra LNG & Midstream and Sempra Mexico.

▪	$206 million charge in 2016 related to Sempra LNG & Midstream’s permanent release of certain pipeline capacity;

▪	$57 million settlement proceeds received by Sempra LNG & Midstream in May 2017 from a breach of contract claim against a counterparty, of which $47 million was related to the charge in 2016 from permanent release of pipeline capacity;

▪	$18 million capacity costs in 2016 on the Rockies Express pipeline that have since been permanently released; and

▪	$16 million due to lower sales of electrical services and materials at Tecnored.

▪	$38 million decrease at Sempra LNG & Midstream primarily due to lower natural gas costs and lower electric fuel costs due to the sale of the remaining block of Mesquite Power in April 2015; and

▪	$21 million decrease at Sempra Mexico primarily due to lower natural gas volumes and costs; offset by

▪	$10 million primarily from lower intercompany eliminations of costs associated with sales between Sempra LNG & Midstream and Sempra Mexico.

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(1)	Includes eliminations of intercompany activity.

▪	$94 million increase at SoCalGas, which included

◦	$54 million higher non-refundable operating costs primarily associated with higher safety-related maintenance and inspection activity, as well as other labor, contract services and administrative and support costs,

◦	$20 million Aliso Canyon litigation reserves in 2017, and

◦	$10 million higher expenses associated with CPUC-authorized refundable programs;

▪	$84 million increase at Sempra Mexico primarily due to the consolidation of IEnova Pipelines and Ventika in 2016, from the growth in Sempra Mexico’s businesses, and from scheduled major maintenance at TdM in the second quarter of 2017; and

▪	$19 million increase at Sempra Renewables primarily due to solar and wind assets placed in service in the fourth quarter of 2016 and higher general and administrative and development costs; offset by

▪	$33 million decrease at Sempra LNG & Midstream, $25 million of which was due to the sale of EnergySouth in September 2016; and

▪	$28 million decrease at SDG&E, which included

◦	$22 million lower expenses associated with CPUC-authorized refundable programs,

◦	$12 million decrease at Otay Mesa VIE primarily due to scheduled major maintenance in 2016 at the OMEC plant, and

◦	$11 million reimbursement of litigation costs associated with the arbitration ruling over the SONGS replacement steam generators, as we discuss in Note 13 of the Notes to Consolidated Financial Statements, offset by

◦	$16 million higher non-refundable operating costs, including labor, contract services and administrative and support costs.

▪	$31 million increase at SDG&E, which included

◦	$40 million higher expenses associated with CPUC-authorized refundable programs, and

◦	$10 million at Otay Mesa VIE primarily due to scheduled major maintenance at the OMEC plant in the second quarter of 2016, offset by

◦	$14 million lower litigation expense, and

◦	$8 million lower non-refundable operating costs, including labor, contract services and administrative and support costs;

▪	$24 million increase at SoCalGas, which included

◦	$52 million higher expenses associated with CPUC-authorized refundable programs, offset by

◦	$33 million lower non-refundable operating costs, including labor, contract services and administrative and support costs; and

▪	$24 million increase at Sempra Mexico primarily from $17 million higher operating costs due to the acquisition of the remaining 50-percent interest in IEnova Pipelines in September 2016; offset by

▪	$21 million decrease at Sempra LNG & Midstream, $9 million of which is attributable to the sale of EnergySouth.

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▪	$1,490 million in 2017

▪	$1,312 million in 2016

▪	$1,250 million in 2015

▪	$79 million increase at Sempra Mexico primarily due to the consolidation of IEnova Pipelines and Ventika in the second half of 2016;

▪	$39 million increase at SoCalGas from depreciation on higher utility plant base;

▪	$32 million increase at Sempra Renewables due to solar and wind assets placed in service in the fourth quarter of 2016; and

▪	$24 million increase at SDG&E primarily from depreciation on higher utility plant base.

▪	$42 million increase at SDG&E from depreciation on higher utility plant base, higher depreciation at Otay Mesa VIE and higher amortization; and

▪	$15 million increase at SoCalGas from depreciation on higher utility plant base.

▪	$34 million in 2017

▪	$6 million in 2016

▪	$104 million in 2015

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▪	$254 million in 2017

▪	$132 million in 2016

▪	$126 million in 2015

▪	$47 million net gains in 2017 on interest rate and foreign exchange instruments, compared to $32 million net losses in 2016 primarily as a result of significant fluctuation of the Mexican peso;

▪	$52 million increase in equity-related AFUDC, including:

◦	$17 million increase at SDG&E, and

◦	$32 million increase at Sempra Mexico primarily from the Ojinaga and San Isidro pipeline projects; and

▪	$33 million higher investment gains in 2017 on dedicated assets in support of our executive retirement and deferred compensation plans; offset by

▪	$34 million higher foreign currency transactional losses in 2017, primarily related to a Mexican peso-denominated note receivable due from IMG JV.

▪	$20 million higher investment gains in 2016 on dedicated assets in support of our executive retirement and deferred compensation plans;

▪	$9 million increase in equity-related AFUDC, including:

◦	$9 million increase at SDG&E, and

◦	$4 million increase at SoCalGas, offset by

◦	$6 million decrease at Sempra Mexico; and

▪	$6 million lower foreign currency losses in 2016; offset by

▪	$28 million higher losses on interest rate and foreign exchange instruments in 2016; and

▪	$6 million lower income from the sale of other investments.

▪	$659 million in 2017

▪	$553 million in 2016

▪	$561 million in 2015

▪	$84 million increase at Sempra Mexico, which included

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◦	$40 million increase due to interest on debt assumed in the IEnova Pipelines and Ventika acquisitions in the second half of 2016,

◦	$28 million increase due to lower capitalized interest due to the recognition of AFUDC mainly related to the Ojinaga and San Isidro pipeline projects in 2017,

◦	$10 million increase in short-term debt at IEnova; and

▪	$11 million increase at Sempra Renewables primarily due to lower capitalized interest as a result of solar and wind assets placed into service in the fourth quarter of 2016.

▪	$26 million higher capitalized interest primarily due to:

◦	$18 million increase at Sempra Renewables primarily for solar projects, and

◦	$10 million increase at Sempra Mexico primarily for the Ojinaga and San Isidro pipeline projects; offset by

▪	$13 million increase at SoCalGas primarily due to debt issuances in 2015 and 2016; and

▪	$6 million higher lease interest on our downtown headquarters building.

▪	Lower U.S. statutory corporate income tax rate: The TCJA reduces the U.S. statutory corporate income tax rate from 35 percent to 21 percent, effective January 1, 2018, which will be applied to our future U.S. earnings. We expect the resultant lower income tax expense at SDG&E and SoCalGas to be allocated to ratepayers.

▪

Deemed repatriation: The TCJA imposes a one-time tax for deemed repatriation of cumulative undistributed earnings of non-U.S. subsidiaries. Under the deemed repatriation provision of the TCJA, a U.S. shareholder must include in taxable income its pro-rata share of cumulative foreign undistributed earnings, which are taxed at 15.5 percent on cash or cash equivalents and 8 percent on cumulative other earnings.

▪	Territorial tax system: The TCJA adopts a territorial system of taxation that replaces the previous worldwide taxation approach. The TCJA provides for a 100 percent dividends received deduction for foreign source dividends, effectively resulting in no federal income taxes on repatriation of foreign earnings after 2017.

▪	Full expensing of depreciable property: Property placed in service after September 27, 2017 is generally eligible for full expensing. Regulated public utilities, including SDG&E and SoCalGas, are not eligible for this treatment.

▪	Limitation of interest deductions: The TCJA limits the deduction for interest expense that exceeds adjusted taxable income. Any disallowed interest expense can be carried forward indefinitely. Regulated public utilities, including SDG&E and SoCalGas, are excepted from this limitation.

▪	Executive compensation deduction limitation: The TCJA amends the definition of a covered employee and eliminates certain exceptions previously allowed under prior law, limiting the annual deductible compensation expense for a covered employee to $1 million.

▪	NOL deductions: U.S. federal NOL carryforwards generated in years starting in 2018 are limited to 80 percent of taxable income. The TCJA permits new NOLs to be carried forward indefinitely, but no longer allows any carryback.

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▪

Lower U.S. statutory corporate income tax rate: The remeasurement of deferred income taxes at the new U.S. statutory corporate federal income tax rate of 21 percent resulted in additional income tax expense of $182 million, $28 million and $2 million for the year ended December 31, 2017 for Sempra Energy Consolidated, SDG&E and SoCalGas, respectively. Due to regulation by the CPUC and FERC, remeasurement impacts at SDG&E and SoCalGas were largely offset by adjustments to regulatory liabilities.

▪

Deemed repatriation: Sempra Energy recorded income tax expense of $328 million associated with the deemed repatriation tax for the year ended December 31, 2017. In addition, we now anticipate that we will repatriate our foreign undistributed earnings (estimated to be approximately $4 billion) that have now been taxed at the U.S. federal level as a result of the deemed repatriation tax. We expect to repatriate approximately $1.6 billion from 2018 through 2022, as cash is generated by our businesses at the local level. We currently anticipate electing to use our existing NOLs to offset the deemed repatriation tax. However, as provided under the TCJA, at the time of filing our tax return in 2018, should we determine that we will pay the deemed repatriation tax over a period of eight years instead of utilizing our NOLs, our income tax expense and cash tax payments would increase. In addition to the deemed repatriation tax, we accrued $360 million of U.S. state and non-U.S. withholding tax on our expected future repatriation of foreign undistributed earnings. This liability could change as a result of various factors, such as interpretation and clarification of the TCJA provisions, changes in foreign tax laws, foreign currency movements, the source of cash to be repatriated, or adjustments to our provisional estimates, as we discuss below.

•	$870 million from effects of the TCJA, as follows:

◦	$688 million income tax expense in 2017 related to future repatriation of foreign earnings, including $328 million of U.S. federal income tax expense pertaining to the deemed repatriation tax and $360 million U.S. state and non-U.S. withholding tax expense on our expected future repatriation of foreign undistributed earnings estimated for deemed repatriation, and

◦	$182 million deferred income tax expense from remeasurement of our U.S. federal deferred income tax balances from 35 percent to 21 percent;

▪	$62 million income tax expense in 2017, compared to $38 million income tax benefit in 2016, from foreign currency and inflation effects, primarily as a result of significant fluctuation of the Mexican peso in 2017; and

▪	$34 million income tax benefit in 2016 associated with excess tax benefits related to share-based compensation; offset by

▪	$33 million income tax benefit in 2017, compared to $3 million income tax expense in 2016, related to the resolution of prior years’ income tax items.

▪

$3 million income tax expense in 2016, compared to $56 million income tax benefit in 2015, from the resolution of prior years’ income tax items. The amount in 2016 included $14 million income tax expense from lower actual repairs deductions at SDG&E and SoCalGas taken on the 2015 tax return compared to amounts estimated in 2015, as discussed in Note 14 of the Notes to Consolidated Financial Statements; and

▪	$17 million income tax expense from the remeasurement of our Peruvian deferred income tax balances as a result of tax reform in Peru as discussed below; offset by

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▪	$34 million income tax benefit in 2016 associated with excess tax benefits related to share-based compensation; and

▪	$40 million lower U.S. income tax expense as a result of a change in planned repatriation from certain non-U.S. subsidiaries.

▪	$12 million higher income tax benefit in 2017 from the resolution of prior years’ income tax items; and

▪	higher flow-through deductions in 2017, including higher AFUDC that is non-taxable; offset by

▪	$28 million deferred income tax expense from remeasurement of U.S. federal deferred income tax balances from 35 percent to 21 percent, primarily from the deferred tax asset relating to the impairments of SONGS SGRP in prior years. We discuss the impairment of SONGS SGRP in Note 13 of the Notes to Consolidated Financial Statements; and

▪	$7 million income tax benefit in 2016 associated with excess tax benefits related to share-based compensation.

▪	$11 million lower income tax benefit in 2016 from the resolution of prior years’ income tax items, including $3 million income tax expense in 2016 from lower actual repairs deductions taken on the 2015 tax return compared to amounts estimated in 2015; offset by

▪	$7 million income tax benefit in 2016 associated with excess tax benefits related to share-based compensation.

▪	$12 million income tax benefit in 2017, compared to $10 million income tax expense in 2016, from the resolution of prior years’ income tax items; offset by

▪	$4 million income tax benefit in 2016 associated with excess tax benefits related to share-based compensation.

▪	$10 million income tax expense in 2016, compared to $18 million income tax benefit in 2015, from the resolution of prior years’ income tax items. The amount in 2016 included $11 million income tax expense from lower actual repairs deductions taken on the 2015 tax return compared to amounts estimated in 2015; offset by

▪	$4 million income tax benefit in 2016 associated with excess tax benefits related to share-based compensation.

▪	$42 million in 2017

▪	$78 million in 2016

▪	$85 million in 2015

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▪	$64 million of equity earnings in 2016 from IEnova Pipelines, including $19 million from DEN, prior to IEnova’s acquisition of the remaining 50-percent interest in IEnova Pipelines in September 2016; and

▪	$13 million equity losses in 2017 from DEN, prior to IEnova’s acquisition of the remaining 50-percent interest in DEN in November 2017, compared to $5 million of equity earnings in 2016, primarily from foreign currency and inflation effects; offset by

▪	$45 million equity earnings from IMG, primarily from AFUDC equity and foreign currency effects, offset by interest expense.

▪	$60 million at Sempra Mexico, primarily due to:

◦	$50 million lower earnings attributable to noncontrolling interests as a result of the decrease in earnings, excluding the effects of foreign currency and inflation, as we discuss above in “Segment Results – Sempra Mexico,” and

◦	$28 million losses attributable to noncontrolling interests in 2017 from foreign currency and inflation effects without the corresponding benefit from foreign currency derivatives that are not subject to noncontrolling interests compared to $14 million earnings in 2016, offset by

◦	$32 million higher earnings attributable to noncontrolling interests, excluding the effects of foreign currency and inflation, from the decrease in our controlling interest from 81.1 percent to 66.4 percent following IEnova’s equity offering in October 2016, which we discuss in Note 1 of the Notes to Consolidated Financial Statements; and

▪	$19 million higher pretax losses attributed to tax equity investors at Sempra Renewables in 2017; offset by

▪	$14 million earnings at SDG&E compared to $5 million losses in 2016, primarily due to an increase in operating expenses as a result of scheduled major maintenance at the OMEC plant in 2016.

▪	$80 million at Sempra Mexico, primarily due to:

◦	$82 million gain associated with the remeasurement of our 50-percent equity interest in IEnova Pipelines, and

◦	$14 million due to the decrease in our controlling interest from 81.1 percent to 66.4 percent following IEnova’s equity offerings in October 2016, offset by

◦	$21 million impairment of TdM assets held for sale; offset by

▪	$24 million decrease at SDG&E, primarily as a result of scheduled major maintenance at the OMEC plant in 2016.

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(1)	Amounts at Sempra Energy Consolidated include $140 million held in non-U.S. jurisdictions. We discuss repatriation in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” above.

(2)	Available unused 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.

(3)	Because the commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding as a reduction to the available unused credit.

▪	finance capital expenditures

▪	meet liquidity requirements

▪	fund shareholder dividends

▪	fund new business or asset acquisitions or start-ups, including our pending acquisition of EFH

▪	repay maturing long-term debt

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▪	fund expenditures related to the natural gas leak at SoCalGas’ Aliso Canyon natural gas storage facility

(1)	The largest amount outstanding at the end of the last day of any month during the year.

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▪	$1.1 billion higher net income, adjusted for noncash items included in earnings, in 2017 compared to 2016, primarily due to improved results at our operating segments;

▪

$188 million net decrease in Insurance Receivable for Aliso Canyon Costs in 2017 compared to a $281 million net increase in 2016. The $188 million net decrease in 2017 primarily includes $300 million in insurance proceeds received, offset by $112 million of additional accruals. We discuss the Aliso Canyon natural gas storage facility leak further in Note 15 of the Notes to Consolidated Financial Statements and in “Item 1A. Risk Factors;”

▪	$31 million net increase in Reserve for Aliso Canyon Costs in 2017 compared to a $221 million net decrease in 2016. The $31 million net increase in 2017 includes $130 million of additional accruals (including $20 million of litigation reserves charged to earnings), offset by $99 million of cash paid;

▪	$66 million decrease in NDT at SDG&E in 2017 as a result of CPUC authorization to withdraw trust funds for SONGS decommissioning costs incurred in the current year; and

▪	$17 million decrease in accounts receivable in 2017 compared to a $42 million increase in 2016; offset by

▪	$54 million increase in net overcollected regulatory balancing accounts (including long-term amounts) at SoCalGas in 2017 compared to a $293 million increase in 2016. 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;

▪	$145 million increase in permanent pipeline capacity release liability at Sempra LNG & Midstream in 2016. We discuss the permanent pipeline capacity releases in Note 15 of the Notes to Consolidated Financial Statements;

▪	$28 million increase in net undercollected regulatory balancing accounts (including long-term amounts) at SDG&E in 2017 compared to a $55 million decrease in 2016;

▪	$70 million increase in income taxes receivable in 2017 compared to a $3 million decrease in 2016; and

▪	$83 million increase in accounts payable in 2017 compared to a $122 million increase in 2016.

▪	$221 million net decrease in Reserve for Aliso Canyon Costs in 2016 compared to a $274 million increase in 2015. The $221 million net decrease includes $654 million of cash expenditures, offset by $433 million of additional accruals;

▪	$268 million lower net income, adjusted for noncash items included in earnings, in 2016 compared to 2015, including charges for income tax benefits previously generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD, as well as lower results at Sempra LNG & Midstream;

▪	$348 million net decrease in undercollected regulatory balancing accounts (including long-term amounts) in 2016 at the California Utilities compared to a $544 million net decrease in 2015;

▪	$93 million higher income tax payments in 2016; and

▪	$20 million increase in inventory in 2016 compared to a $65 million decrease in 2015; offset by

▪	$122 million increase in accounts payable in 2016 compared to a $157 million decrease in 2015, primarily due to higher average cost of natural gas purchased at SoCalGas, as well as higher gas purchases as a result of the moratorium on natural gas injections at the Aliso Canyon natural gas storage facility;

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▪	$145 million increase in permanent pipeline capacity release liability at Sempra LNG & Midstream;

▪	$42 million increase in accounts receivable in 2016 compared to a $99 million increase in 2015. The 2015 increase was primarily due to an increase in physical gas sales at SoCalGas;

▪	$281 million net increase in Insurance Receivable for Aliso Canyon Costs in 2016 compared to a $325 million increase in 2015. The $281 million net increase in 2016 included $450 million of additional accruals, offset by $169 million in insurance proceeds;

▪	$36 million net decrease in GHG allowance purchases at the California Utilities; and

▪	$23 million reduction to the SONGS regulatory asset due to cash received for SDG&E’s portion of the DOE settlement with Edison related to spent fuel storage, as we discuss in Note 15 of the Notes to Consolidated Financial Statements.

▪	$136 million decrease in income taxes receivable in 2017 compared to a $115 million increase in 2016, primarily due to timing of tax payments;

▪	$66 million decrease in NDT in 2017 as a result of CPUC authorization to withdraw trust funds for SONGS decommissioning costs incurred in the current year;

▪	$15 million in purchases of GHG allowances in 2017 compared to $58 million in 2016; and

▪	$75 million increase in accounts payable in 2017 compared to a $39 million increase in 2016; offset by

▪	$28 million increase in net undercollected regulatory balancing accounts (including long-term amounts) in 2017 compared to a $55 million decrease in 2016;

▪	$76 million increase in accounts receivable in 2017 compared to a $31 million increase in 2016; and

▪	$23 million lower net income, adjusted for noncash items included in earnings, in 2017 compared to 2016.

▪	$55 million decrease in net undercollected regulatory balancing accounts (including long-term amounts) in 2016 compared to a $474 million decrease in 2015, primarily due to changes in electric commodity accounts;

▪	$49 million higher income tax payments in 2016; and

▪	$19 million increase in receivables due from affiliates in 2016 compared to a $21 million decrease in 2015; offset by

▪	$72 million higher net income, adjusted for noncash items included in earnings, in 2016 compared to 2015;

▪	$58 million in purchases of GHG allowances in 2016 compared to $117 million in 2015; and

▪	$23 million reduction to the SONGS regulatory asset due to cash received for SDG&E’s portion of the DOE settlement with Edison related to spent fuel storage.

▪	$188 million net decrease in Insurance Receivable for Aliso Canyon Costs in 2017 compared to a $281 million net increase in 2016. The $188 million net decrease in 2017 primarily includes $300 million in insurance proceeds received, offset by $112 million of additional accruals;

▪	$31 million net increase in Reserve for Aliso Canyon Costs in 2017 compared to a $221 million net decrease in 2016. The $31 million net increase in 2017 includes $130 million of additional accruals (including $20 million of litigation reserves charged to earnings), offset by $99 million of cash paid;

▪	$135 million higher net income, adjusted for noncash items included in earnings, in 2017 compared to 2016;

▪	$20 million net source of cash due to changes in other current assets and liabilities in 2017 compared to a $38 million net use of cash in 2016; and

▪	$72 million decrease in accounts receivable in 2017 compared to a $37 million decrease in 2016; offset by

▪	$54 million increase in net overcollected regulatory balancing accounts (including long-term amounts) in 2017 compared to a $293 million increase in 2016; and

▪	$66 million increase in inventory in 2017 compared to a $4 million decrease in 2016.

▪	$221 million net decrease in Reserve for Aliso Canyon Costs in 2016 compared to a $274 million increase in 2015. The $221 million net decrease includes $654 million of cash expenditures, offset by $433 million of additional accruals;

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▪	$4 million decrease in inventory in 2016 compared to a $102 million decrease in 2015. The decrease in 2015 was primarily due to the moratorium on natural gas injections at the Aliso Canyon natural gas storage facility;

▪	$72 million lower net income, adjusted for noncash items included in earnings, in 2016 compared to 2015;

▪	$40 million higher income tax payments in 2016;

▪	$10 million decrease in accrued compensation in 2016 compared to a $31 million increase in 2015; and

▪	$85 million in purchases of GHG allowances in 2016 compared to $62 million in 2015; offset by

▪	$36 million increase in accounts payable in 2016 compared to a $143 million decrease in 2015. The 2015 decrease was primarily due to the moratorium on natural gas injections at the Aliso Canyon natural gas storage facility, as well as lower average cost of natural gas purchased;

▪	$293 million increase in net overcollected regulatory balancing accounts (including long-term amounts) in 2016 compared to a $70 million decrease in net undercollected regulatory balancing accounts in 2015, primarily due to changes in fixed-cost balancing accounts;

▪	$37 million decrease in accounts receivable in 2016 compared to a $90 million increase in 2015. The increase in 2015 was primarily due to an increase in physical gas sales; and

▪	$281 million net increase in Insurance Receivable for Aliso Canyon Costs in 2016 compared to a $325 million increase in 2015. The $281 million net increase in 2016 included $450 million of additional accruals, offset by $169 million in insurance proceeds.

(1)	Reflects the adoption of ASU 2016-15 and ASU 2016-18, as we discuss in Note 2 of the Notes to Consolidated Financial Statements.

▪	$1.2 billion decrease in expenditures for investments and acquisition of businesses, as we discuss below; and

▪	$265 million decrease in capital expenditures, as we discuss below; offset by

▪	$506 million higher advances to unconsolidated affiliates, mainly to the IMG joint venture to finance construction of a natural gas marine pipeline;

▪	$443 million net proceeds received from Sempra LNG & Midstream’s sale of its 25-percent interest in Rockies Express in 2016;

▪	$318 million net proceeds received from Sempra LNG & Midstream’s sale of EnergySouth in 2016; and

▪	$100 million decrease in NDT assets in 2016 as a result of CPUC authorization to withdraw trust funds for SONGS decommissioning costs incurred in prior years.

▪	$1.3 billion increase in expenditures for investments and acquisition of businesses;

▪	$1.1 billion increase in capital expenditures;

▪	$347 million of net proceeds received in 2015 from Sempra LNG & Midstream’s sale of the remaining 625-MW block of its Mesquite Power plant and a related power sale contract; and

▪	$63 million lower repayments of advances to unconsolidated affiliates; offset by

▪	$443 million net proceeds received from Sempra LNG & Midstream’s sale of its investment in Rockies Express in 2016;

▪	$318 million net proceeds from Sempra LNG & Midstream’s sale of EnergySouth in 2016; and

▪	$100 million decrease in NDT assets in 2016 as a result of CPUC authorization to withdraw trust funds for SONGS decommissioning costs incurred in prior years, compared to a $60 million decrease in 2015.

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▪	$156 million increase in capital expenditures; and

▪	$100 million decrease in NDT assets in 2016 as a result of CPUC authorization to withdraw trust funds for SONGS decommissioning costs incurred in prior years; offset by

▪	$31 million decrease in advances to Sempra Energy in 2017 compared to a $31 million increase in 2016.

▪	$266 million increase in capital expenditures; and

▪	$31 million net advances to Sempra Energy; offset by

▪	$100 million decrease in NDT assets in 2016 as a result of CPUC authorization to withdraw trust funds for SONGS decommissioning costs incurred in prior years, compared to a $60 million decrease in 2015.

▪	$50 million net decrease in advances to Sempra Energy in 2016; and

▪	$48 million increase in capital expenditures.

▪	$50 million net decrease in advances to Sempra Energy in 2016 compared to a $50 million net increase in 2015; and

▪	$33 million lower capital expenditures.

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(1)	Net of cash, cash equivalents and restricted cash acquired.

(2)	Reflects the adoption of ASU 2016-15 and ASU 2016-18, as we discuss in Note 2 of the Notes to Consolidated Financial Statements.

(3)	Excludes accrued purchase price of $5 million in 2015.

(4)	Includes capitalized interest of $47 million, $47 million and $49 million in 2017, 2016 and 2015, respectively, on Sempra LNG & Midstream’s investment, as the joint venture has not commenced planned principal operations.

(5)	Investment in industrial development bonds.

(6)	Repayment of project debt that matured in early 2015.

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(1)	Reflects the adoption of ASU 2016-15 and ASU 2016-18, as we discuss in Note 2 of the Notes to Consolidated Financial Statements.

▪	$1.2 billion proceeds received in 2016 from the IEnova follow-on common stock offerings, net of offering costs and Sempra Energy’s participation, as we discuss in Note 1 of the Notes to Consolidated Financial Statements;

▪	$743 million higher payments on debt with maturities greater than 90 days, including:

◦	$828 million higher payments of commercial paper and other short-term debt ($1.9 billion in 2017 compared to $1.07 billion in 2016), offset by

◦	$85 million lower payments on long-term debt ($906 million in 2017 compared to $991 million in 2016);

▪	$36 million net decrease in short-term debt in 2017 compared to a $692 million net increase in 2016;

▪	$196 million net proceeds from tax equity funding from certain wind and solar power generation projects at Sempra Renewables in 2017 compared to $474 million in 2016;

▪	$69 million increase in common stock dividends paid in 2017; and

▪	$67 million increase in net distributions to noncontrolling interests; offset by

▪	$1.6 billion higher issuances of debt with maturities greater than 90 days, including:

◦	$1.4 billion for long-term debt ($3 billion in 2017 compared to $1.6 billion in 2016), and

◦	$172 million for commercial paper and other short-term debt ($1.6 billion in 2017 compared to $1.4 billion in 2016).

▪	$692 million net increase in short-term debt in 2016 compared to a $622 million net decrease in 2015;

▪	$1.2 billion proceeds received from the IEnova follow-on common stock offerings, net of offering costs and Sempra Energy’s participation; and

▪	$474 million net proceeds from tax equity funding from certain wind and solar power generation projects at Sempra Renewables; offset by

▪	$203 million higher payments of debt with maturities greater than 90 days, including:

◦	$255 million higher payments of long-term debt ($991 million in 2016 compared to $736 million in 2015), offset by

◦	$52 million lower payments of commercial paper and other short-term debt ($1.07 billion in 2016 compared to $1.12 billion in 2015);

▪	$58 million increase in common stock dividends paid in 2016;

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▪	$52 million from excess tax benefits related to share-based compensation in 2015. In connection with the adoption of a new accounting standard related to share-based compensation, $34 million of similar excess tax benefits are now recorded to earnings and included as an operating activity beginning in 2016; and

▪	$41 million lower issuances of debt with maturities greater than 90 days, including:

◦	$812 million lower issuances of long-term debt ($1.6 billion in 2016 compared to $2.4 billion in 2015), offset by

◦	$771 million higher issuances of commercial paper and other short-term debt ($1.4 billion in 2016 compared to $633 million in 2015).

▪	$275 million increase in common stock dividends paid in 2017; and

▪	$100 million lower issuances of long-term debt in 2017; offset by

▪	$253 million net increase in short-term debt in 2017 compared to a $114 million net decrease in 2016.

▪	$343 million lower payments on long-term debt in 2016;

▪	$125 million decrease in common stock dividends paid in 2016; and

▪	$54 million higher issuances of long-term debt in 2016.

▪	$62 million increase in short-term debt in 2016 compared to a $50 million decrease in 2015; and

▪	$50 million common stock dividends paid in 2015; offset by

▪	$100 million lower issuances of long-term debt in 2016.

(1)	Includes current portion of long-term debt.

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▪	for general working capital purposes;

▪	to support their electric (at SDG&E) and natural gas (at SDG&E and SoCalGas) procurement programs;

▪	to repay commercial paper, maturing long-term debt and certain long-term debt prior to maturity; and

▪	to replenish amounts expended and to fund future expenditures for the expansion and improvement of their utility plants.

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▪	$47 million in 2017

▪	$51 million in 2016

▪	$52 million in 2015

▪	$755 million in 2017

▪	$686 million in 2016

▪	$628 million in 2015

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▪	$50.40 in 2017

▪	$51.77 in 2016

▪	$47.56 in 2015

(1)	Includes Otay Mesa VIE with no significant impact.

▪	Sempra Energy Consolidated: increase in long-term debt as well as dividends exceeding comprehensive income, partially offset by the sale of noncontrolling interests and a decrease in short-term debt.

▪	SDG&E: increase in both long-term and short-term debt as well as dividends exceeding comprehensive income.

▪	SoCalGas: comprehensive income exceeding an increase in short-term debt.

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(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 based on forward rates in effect at December 31, 2017.

(2)	Present value of the net minimum lease payments includes $550 million at SDG&E that will be recorded as a capital lease obligation when construction of the power plant facility subject to the lease is completed and delivery of contracted power commences, which is scheduled to occur in 2018.

(3)	Sempra LNG & Midstream has a purchase agreement with a major international company for the supply of LNG to the ECA terminal. The commitment amount is calculated using a predetermined formula based on estimated forward prices of the index applicable from 2018 to 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.

(1)	SDG&E calculates expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps.

(2)	Present value of the net minimum lease payments includes $550 million that will be recorded as a capital lease obligation when construction of the power plant facility subject to the lease is completed and delivery of contracted power commences, which is scheduled to occur in 2018.

(3)	Amounts represent expected SDG&E contributions to the plans for the next 10 years.

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(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.

▪	contracts between consolidated affiliates

▪	intercompany debt

▪	employment contracts

▪	$57 million for Sempra Energy Consolidated

▪	$10 million for SDG&E

▪	$35 million for SoCalGas

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▪	A majority of the independent directors of Oncor must approve any annual or multi-year budget if the aggregate amount of capital expenditures or operating and maintenance expenditures in such budget is more than a 10 percent increase or decrease from the corresponding amounts of such expenditures in the budget for the preceding fiscal year or multi-year period, as applicable;

▪	Oncor will make minimum aggregate capital expenditures equal to at least $7.5 billion over the period from January 1, 2018 through December 31, 2022 (subject to certain possible adjustments);

▪	Sempra Energy has agreed to make, within 60 days after the Merger, its proportionate share of the aggregate equity investment in Oncor in an amount necessary for Oncor to achieve a capital structure consisting of 57.5 percent long-term debt and 42.5

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▪	Oncor may not pay any dividends or make any other distributions (except for contractual tax payments) if a majority of its independent directors or a minority member director determines that it is in the best interests of Oncor to retain such amounts to meet expected future requirements;

▪	At all times, Oncor will remain in compliance with the debt-to-equity ratio established by the PUCT from time to time for ratemaking purposes, and Oncor will not pay dividends or other distributions (except for contractual tax payments), if that payment would cause its debt-to-equity ratio to exceed the debt-to-equity ratio approved by the PUCT;

▪	Sempra Energy will ensure that, as of the closing of the Merger, Oncor’s credit rating by all three major rating agencies will be at or above Oncor’s credit ratings as of June 30, 2017;

▪	If the credit rating on Oncor’s senior secured debt by any of the three major rating agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT;

▪

Without the prior approval of the PUCT, neither Sempra Energy nor any of its affiliates (excluding Oncor) will incur, guarantee or pledge assets in respect of any indebtedness that is dependent on the revenues of Oncor in more than a proportionate degree than the other revenues of Sempra Energy or on the stock of Oncor, and there will be no debt at EFH or EFIH at any time following the closing of the Merger;

▪

Neither Oncor nor Oncor Holdings will lend money to or borrow money from Sempra Energy or any of its affiliates (other than Oncor subsidiaries), or any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings, and neither Oncor nor Oncor Holdings will share credit facilities with Sempra Energy or any of its affiliates (other than Oncor subsidiaries), or any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings;

▪

Oncor will not seek recovery in rates of any expenses or liabilities related to EFH’s bankruptcy, or (1) any tax liabilities resulting from EFH’s spinoff of its former subsidiary Texas Competitive Electric Holdings Company LLC, (2) any asbestos claims relating to non-Oncor operations of EFH or (3) any make-whole claims by holders of debt securities issued by EFH or EFIH, and Sempra Energy must file with the PUCT a plan providing for the extinguishment of the liabilities described in items (1) through (3) above, which protects Oncor from any harm;

▪

There must be maintained certain “separateness measures” that reinforce the financial separation of Oncor from EFH and EFH’s owners, including a requirement that dealings between Oncor, Oncor Holdings and their subsidiaries and Sempra Energy, any of Sempra Energy’s other affiliates or any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings, must be on an arm’s-length basis, limitations on affiliate transactions, separate recordkeeping requirements and a prohibition on pledging Oncor assets or stock for any entity other than Oncor;

▪	No transaction costs or transition costs related to the Merger (excluding Oncor employee time) will be borne by Oncor’s customers nor included in Oncor’s rates;

▪	Sempra Energy will continue to hold indirectly at least 51 percent of the ownership interests in Oncor and Oncor Holdings for at least five years following the closing of the Merger, unless otherwise specifically authorized by the PUCT; and

▪

Oncor will provide bill credits to customers in an amount equal to 90 percent of any interest rate savings achieved due to any improvement in its credit ratings or market spreads compared to those as of June 30, 2017 until final rates are set in the next Oncor base rate case filed after PUCT Docket No. 46957 (except that savings will not be included in credits if already realized in rates); and one year after the Merger, Oncor will provide bill credits to its customers equal to 90 percent of any synergy savings until final rates are set in the next Oncor base rate proceeding after PUCT Docket No. 46957, at which time any total synergy savings shall be reflected in Oncor’s rates.

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▪	the revised settlement agreement, which is subject to CPUC approval, that provides a different cost allocation among ratepayers and shareholders associated with the premature shutdown of SONGS Units 2 and 3 than the 2014 agreement;

▪	matters concerning the ability to timely withdraw funds from trust accounts for the payment of decommissioning costs; and

▪	the arbitration decision finding MHI liable for breach of contract in connection with the replacement steam generators at the SONGS nuclear power plant, subject to a contractual limitation of liability, and awarding MHI 95 percent of its arbitration costs as MHI was found to be the prevailing party.

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▪

In January 2016, the Governor of the State of California issued an order (the Governor’s Order) proclaiming a state of emergency in Los Angeles County due to the Leak. The Governor’s Order imposes 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 and the CARB’s Aliso Canyon Methane Leak Climate Impacts Mitigation Program, issued pursuant to the Governor’s Order, in Note 15 of the Notes to Consolidated Financial Statements.

▪	In January 2016, DOGGR and the CPUC selected Blade Energy Partners to conduct an independent analysis under their direction and supervision to be funded by SoCalGas to investigate the technical root cause of the Leak. The timing of the root cause analysis is under the control of Blade Energy Partners, DOGGR and the CPUC.

▪	In February 2017, the CPUC opened a proceeding pursuant to SB 380 to determine the feasibility of minimizing or eliminating use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region, as we discuss below in “Regulatory Proceedings” and “SB 380.”

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▪	requires PHMSA to issue, within two years of passage, “minimum safety standards for underground natural gas storage facilities;”

▪	imposes a “user fee” on underground storage facilities as needed to implement the safety standards;

▪

grants PHMSA authority to issue emergency orders and impose emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for hearing, if the U.S. Secretary of Energy determines that an unsafe condition or practice, or a combination of unsafe conditions and practices, constitutes or is causing an imminent hazard; and

▪	directs the U.S. Secretary of Energy to establish an Interagency Task Force comprised of representatives from various federal agencies and representatives of state and local governments.

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(1)	2017 awards reflect settlement reductions as approved by the CPUC, as discussed below.

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(1)	Excludes disallowed costs through December 31, 2017 of $7 million at SoCalGas and $4 million at SDG&E for pressure testing or replacing pipelines installed between January 1, 1956 and July 1, 1961.

(2)	Approved in December 2016; excludes $2 million of PSEP-specific insurance costs for which SoCalGas and SDG&E are authorized to request recovery in a future filing.

(3)	Reasonableness Review Application for completed projects totaling $195 million filed in September 2016. Also includes approximately $11 million of pre-engineering costs incurred to support projects under development and submitted as part of the Forecast Application filed in March 2017. Both decisions are expected in 2018.

(4)	Authorized to recover in rates 50 percent of the balances recorded in the PSEP balancing accounts, subject to refund.

(5)	Reasonableness Review Application to be filed in late 2018 and expected to include the majority of these costs. Remaining costs not the subject of prior applications are to be included for review in subsequent GRCs.

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(1)	See discussion in Note 15 of the Notes to Consolidated Financial Statements.

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▪	The proposed project is designed to include

◦	two natural gas liquefaction trains with production capability of approximately 13.5 Mtpa, or 698 Bcf per year;

◦	three LNG storage tanks;

◦	natural gas liquids and refrigerant storage;

◦	feed gas pre-treatment facilities; and

◦	two berths and associated marine and loading facilities.

▪	In June 2015, Sempra LNG & Midstream filed permit applications with the DOE for authorization to export the LNG produced from the proposed project to all current and future non-FTA countries.

▪	In August 2015, Sempra LNG & Midstream received authorization from the DOE to export the LNG produced from the proposed project to all current and future FTA countries.

▪

In June 2017, Sempra LNG & Midstream, Woodside Petroleum Ltd. and Korea Gas Corporation signed a memorandum of understanding that provides a framework for cooperation and joint discussion by the parties regarding key aspects of the potential development of the Port Arthur LNG project, including engineering and construction work, O&M activities, feed gas sourcing, offtake of LNG and the potential for Korea Gas Corporation to purchase LNG from, and become an equity participant in, the Port Arthur LNG project. The memorandum of understanding does not commit any party to buy or sell LNG or otherwise participate in the Port Arthur liquefaction LNG project.

▪

In February 2018, Sempra LNG & Midstream and Woodside Petroleum Ltd. 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.

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(1)	Before the effects of acquisition-related fair value adjustments, interest rate swaps, reductions/increases for unamortized discount/premium and reduction for debt issuance costs, and excluding capital lease obligations and build-to-suit lease.

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▪	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

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(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 December 31, 2017 on monetary assets and liabilities and translation of non-U.S. deferred income tax balances at our Mexican subsidiaries.

(3)	Amount represents the effects of currency exchange rate movement from December 31, 2017 recorded to OCI at the end of each reporting period, primarily at our South American businesses.

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(1)	In 2017, Sempra Energy Consolidated includes $1 million and $0.3 million of audit and audit-related fees, respectively, related to our pending acquisition of EFH and associated financing transactions.

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(1)	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

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(1)	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

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(1)	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

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(1)	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

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(1)	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

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(1)	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

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(1)	As adjusted for the retrospective adoption of ASU 2016-15 and ASU 2016-18, which we discuss in Note 2.

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(1)	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

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(1)	Reflects reclassifications to conform to current year presentation, which we discuss in Note 1.

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▪	Sempra Utilities, which includes our SDG&E, SoCalGas and Sempra South American Utilities reportable segments; and

▪	Sempra Infrastructure, which includes our Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream reportable segments.

▪	the Consolidated Financial Statements and related Notes of Sempra Energy and its subsidiaries and VIEs;

▪	the Consolidated Financial Statements and related Notes of SDG&E and its VIE; and

▪	the Financial Statements and related Notes of SoCalGas.

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▪	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;

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▪	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.

▪	quoted forward prices for commodities

▪	time value

▪	current market and contractual prices for the underlying instruments

▪	volatility factors

▪	other relevant economic measures

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▪	for SDG&E, $17 million and $12 million at December 31, 2017 and 2016, respectively, representing funds held by a trustee for Otay Mesa VIE to pay certain operating costs.

▪	for Sempra Mexico, $56 million and $61 million at December 31, 2017 and 2016, respectively, primarily denominated in Mexican pesos, representing funds to pay for rights-of-way, license fees, permits, topographic surveys and other costs pursuant to trust and debt agreements related to pipeline projects.

▪	for Sempra Renewables, $3 million at both December 31, 2017 and 2016, primarily representing funds held in accordance with debt agreements at our wholly owned solar project.

▪	for Sempra South American Utilities, negligible amounts at both December 31, 2017 and 2016.

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(1)	At December 31, 2016, SoCalGas’ natural gas inventory for core customers is net of an inventory loss related to the Aliso Canyon natural gas storage facility leak, which we discuss in Note 15.

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▪	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.

▪	labor

▪	materials and contract services

▪	expenditures for replacement parts incurred during a major maintenance outage of a generating plant

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(1)

At December 31, 2017, includes $440 million in electric transmission assets and $29 million in construction work in progress related to SDG&E’s 92-percent interest in the Southwest Powerlink 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. SDG&E’s share of operating expenses is included in Sempra Energy’s and SDG&E’s Consolidated Statements of Operations.

(2)	Includes capital lease assets of $757 million and $258 million at December 31, 2017 and 2016, respectively.

(3)	Includes capital lease assets of $22 million and $21 million at December 31, 2017 and 2016, respectively.

(4)	Includes capital lease assets of $34 million and $32 million at December 31, 2017 and 2016, respectively.

(5)	Includes $145 million and $128 million at December 31, 2017 and 2016, respectively, of utility plant, primarily pipelines and other distribution assets, at Ecogas.

(6)	Estimated useful lives are for land rights.

(7)	Includes capital lease assets of $136 million at both December 31, 2017 and 2016, related to a build-to-suit lease.

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(1)	Includes accumulated depreciation for capital lease assets of $47 million and $39 million at December 31, 2017 and 2016, respectively. Includes $241 million at December 31, 2017 related to SDG&E’s 92-percent interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities.

(2)	Includes accumulated depreciation for capital lease assets of $33 million and $31 million at December 31, 2017 and 2016, respectively.

(3)	Includes $39 million and $33 million at December 31, 2017 and 2016, respectively, of accumulated depreciation for utility plant at Ecogas.

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▪	consideration of market transactions

▪	future cash flows

▪	the appropriate risk-adjusted discount rate

▪	country risk

▪	entity risk

(1)	We record the offset of this fluctuation to Other Comprehensive Income (Loss).

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▪	storage and development rights related to the Bay Gas and Mississippi Hub natural gas storage facilities.

▪	a renewable energy transmission and consumption permit previously granted by the CRE that was acquired in connection with the acquisition of the Ventika wind power generation facilities.

▪	a favorable O&M agreement acquired in connection with the acquisition of DEN, which we discuss in Note 3.

▪	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

▪	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 the right to receive benefits that could be significant to the VIE.

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▪	fuel and storage tanks

▪	natural gas transmission systems

▪	natural gas distribution systems

▪	hazardous waste storage facilities

▪	asbestos-containing construction materials

▪	decommissioning of nuclear power facilities

▪	electric distribution and transmission systems

▪	energy storage systems

▪	site restoration of a former power plant

▪	power generation plant (natural gas)

▪	underground natural gas storage facilities and wells

▪	electric distribution and transmission systems

▪	power generation plant (natural gas) (classified as held for sale at December 31, 2017)

▪	natural gas distribution and transportation systems

▪	LNG terminal

▪	LPG terminal

▪	wind farm

▪	certain power generation plants (solar and wind)

▪	natural gas transportation systems

▪	underground natural gas storage facilities

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(1)	Current portions of the obligations for Sempra Energy Consolidated and SoCalGas are included in Other Current Liabilities on the Consolidated Balance Sheets.

(2)	Deconsolidated $12 million due to the September 2016 sale of EnergySouth and reclassified $4 million to Liabilities Held for Sale, as we discuss in Note 3.

(3)	In 2017, revised estimates were primarily related to underground natural gas storage facilities and wells at SoCalGas. In 2016, revised estimates were related to changes in the cost of removal rates primarily for natural gas assets based on updated cost studies approved in the 2016 GRC FD.

▪	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.

▪	foreign currency translation adjustments

▪	certain hedging activities

▪	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

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(1)	All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.

(2)	Total AOCI includes $20 million associated with the October 2016 sale of noncontrolling interests, discussed below in “Sale of Noncontrolling Interests – Sempra Mexico – Follow-On Offerings,” which does not impact the Consolidated Statement of Comprehensive Income.

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(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.

(2)	Amounts are included in the computation of net periodic benefit cost (see “Net Periodic Benefit Cost” in Note 7).

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(1)	Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.

(2)	IEnova has a subsidiary with a 10-percent noncontrolling interest held by others. The equity held by noncontrolling interests is negligible at December 31, 2017 and 2016.

(3)	Net income or loss attributable to the noncontrolling interests is computed using the HLBV method and is not based on ownership percentages.

(4)	We sold our assets in Southern Gas Transmission Company in August 2017.

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▪

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 a subsequent period. 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 their 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 a subsequent period. The California Utilities may also record revenue from CPUC-approved incentive awards, some of which require approval by the CPUC prior to being recognized. SDG&E bids and self-schedules its generation into the CAISO energy market on a day-ahead and real-time basis and self-schedules power to serve the demand of its customers. Generally, SDG&E is a net purchaser of power. The CAISO settles SDG&E costs and revenues on an hourly and real-time net basis.

(1)	Excludes intercompany revenues.

▪	pipeline transportation and storage of natural gas, LPG and ethane as capacity is provided. Certain of the revenues recognized from pipelines are under contracts that are accounted for as operating leases;

▪	sale of natural gas as deliveries are made;

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▪	an LNG regasification terminal that generates revenues from reservation and usage fees under terminal capacity agreements and nitrogen injection service agreements as capacity is provided;

▪	wind power generation facilities that generate revenues from selling electricity as the power is delivered at the interconnection point; and

▪	TdM, a natural gas-fired power plant that generates revenues from selling electricity and/or capacity to the CAISO and to governmental, public utility and wholesale power marketing entities as the power is delivered at the interconnection point. At December 31, 2017, TdM is classified as held for sale, as we discuss in Note 3.

▪	pipeline capacity costs, including the permanent release of pipeline capacity in 2016 and the associated recoveries in 2017, at Sempra LNG & Midstream;

▪	pipeline transportation and natural gas marketing costs at Sempra LNG & Midstream;

▪	electric construction services costs at Sempra South American Utilities’ energy-services companies; and

▪	energy management service fees and costs associated with construction performed for and invoiced to third parties at Sempra Mexico.

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(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, comprising joint ventures of Chilquinta Energía.

(3)	Mexican peso-denominated revolving line of credit for up to $14.0 billion Mexican pesos or approximately $718 million U.S. dollar-equivalent, at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus 220 bps (9.87 percent at December 31, 2017), to finance construction of the natural gas marine pipeline.

(4)	Four U.S. dollar-denominated loans, at a variable interest rate based on the 30-day LIBOR plus 450 bps (5.27 percent at December 31, 2016), to finance the Los Ramones Norte pipeline project. In November 2017, IEnova acquired the remaining 50-percent interest in DEN and DEN became a wholly owned, consolidated subsidiary of IEnova.

(5)	U.S. dollar-denominated loan, at a variable interest rate based on the 30-day LIBOR plus 637.5 bps (7.94 percent at December 31, 2017) with no stated maturity date, to finance the first phase of the Energía Sierra Juárez wind project, which is a joint venture of IEnova.

(6)	U.S. dollar-denominated loan, at a variable interest rate based on 6-month LIBOR plus 290 bps (4.74 percent at December 31, 2017).

(7)	At December 31, 2016, net receivable included outstanding advances to Sempra Energy of $31 million at an interest rate of 0.68 percent.

(8)	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.

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▪	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, 2017 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.

▪	Mexico requires domestic corporations to maintain minimum legal reserves as a percentage of capital stock, resulting in restricted net assets of $198 million at Sempra Energy’s consolidated Mexican subsidiaries at December 31, 2017.

▪	Wholly owned IEnova Pipelines has a long-term debt agreement that requires it to maintain a reserve account to pay the projects’ debt. Under this restriction, net assets totaling $19 million are restricted at December 31, 2017.

▪

Wholly owned Ventika has long-term debt agreements that require it to maintain reserve accounts to pay the projects’ debt. The debt agreements may limit the project companies’ ability to incur liens, incur additional indebtedness, make investments, pay cash dividends and undertake certain additional actions. Under these restrictions, net assets totaling $34 million are restricted at December 31, 2017.

▪

Energía Sierra Juárez, a 50-percent owned and unconsolidated joint venture of Sempra Mexico, has long-term debt agreements that require the establishment and funding of project and reserve accounts to which the proceeds of loans, letter of credit borrowings, project revenues and other amounts are deposited and applied in accordance with the debt agreements. The long-term debt agreements also limit the joint venture’s ability to incur liens, incur additional indebtedness, make acquisitions and undertake certain actions. Under these restrictions, net assets totaling $9 million are restricted at December 31, 2017.

▪	TAG, a 50-percent owned and unconsolidated joint venture of Sempra Mexico, has a long-term debt agreement that requires it to maintain a reserve account to pay projects’ debt. Under these restrictions, net assets totaling $82 million are restricted at December 31, 2017.

▪	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 the solar project’s ability to incur liens, incur additional

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Tax equity limited liability companies at Sempra Renewables are required to maintain completion reserve depository accounts to be used to pay for trailing construction costs that become due subsequent to the tax equity transaction closing. At December 31, 2017, as a result of these requirements, there were total restricted net assets at these tax equity limited liability companies of approximately $19 million.

▪

50- and 25-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 O&M requirements. We discuss Sempra Energy guarantees associated with these requirements in Note 4. At December 31, 2017, as a result of these requirements, there were total restricted net assets at these joint ventures of approximately $265 million.

▪

Sempra LNG & Midstream 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 $7.0 billion are restricted at December 31, 2017.

(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, recorded in Operation and Maintenance on the Consolidated Statements of Operations.

(2)	Includes $35 million loss from translation of Mexican peso-denominated loan to IMG JV to U.S. dollars.

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▪	Issue 1 – debt prepayment or debt extinguishment costs

▪	Issue 3 – contingent consideration payments made after a business combination

▪	Issue 5 – proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies)

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(1)

During the fourth quarter of 2016, we received additional information regarding IEnova Pipelines’ deferred income taxes as of the acquisition date, primarily related to basis differences in IEnova Pipelines’ PP&E. As a result, we recorded measurement period adjustments that resulted in a net increase to goodwill of $86 million, an increase in deferred income tax liabilities of $119 million and $33 million of regulatory assets related to deferred income taxes on AFUDC.

(2)	During the fourth quarter of 2017, we received additional information regarding Ventika’s deferred income taxes as of the acquisition date, primarily related to net operating loss carryforwards. As a result, we recorded a measurement period adjustment that resulted in a decrease to goodwill and an increase in deferred income tax assets of $13 million.

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▪	PP&E – We applied an income approach using market-based discounted cash flows. We used the pricing included in the existing PPAs, which was determined to reflect current market rates in the Mexican renewable energy market.

▪

Intangible asset – Ventika is the holder of a renewable energy transmission and consumption permit that allows it to transmit its generated power to various locations within Mexico at beneficial rates and reduces the administrative burden to manage transmitting power to off-takers. With recent renewable energy market reforms in Mexico, these transmission and consumption permits are no longer available, resulting in higher tariffs for generators. We applied an income approach based on a cash flow differential approach that measures the fair value of the transmission rights by comparing the operating expenses under the transmission and consumption permit as compared to under the new, higher tariffs. This acquired intangible asset has an amortization period of 19 years, reflecting the remaining life of the transmission and consumption transmission permit at the time of acquisition.

▪	Debt – Using an income approach, we valued debt by discounting future debt payments by a market yield commensurate with the remaining term of the loans.

▪	Derivatives – Using an income approach, we valued derivatives by discounting the future interest payments under the fixed and floating rates using current market data.

▪	the related IEnova equity offerings, discussed above and in Note 1, occurred on January 1, 2015, which results in a change in Sempra Energy’s noncontrolling interest in IEnova from 18.9 percent to 33.6 percent for all periods presented;

▪	the proceeds from the IEnova equity offerings were used to fund the acquisitions, instead of the bridge loan that was provided by Sempra Global to IEnova for the IEnova Pipelines acquisition, therefore interest expense on the commercial paper borrowings supporting the bridge loan is excluded for all periods presented;

▪	interest expense on the borrowings against Sempra Mexico’s revolving credit facility began when Ventika’s commercial operations commenced in April 2016;

▪	equity earnings, net of income tax, from IEnova Pipelines that were previously included in Sempra Energy’s results have been excluded for both periods presented;

▪	the gain related to the remeasurement of our previously held equity interest in IEnova Pipelines has been included in the year ended December 31, 2015, and accordingly, the year ended December 31, 2016 was adjusted to exclude the gain; and

▪	acquisition-related transaction costs have been included in the year ended December 31, 2015, and accordingly, the year ended December 31, 2016 was adjusted to exclude them.

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seven members will be independent directors in all material respects under the rules of the New York Stock Exchange in relation to Sempra Energy and its subsidiaries and affiliated entities and any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings (and those directors must have no material relationship with Sempra Energy or its affiliates or any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings at the time of the Merger or within the previous ten years) (“independent directors”);

▪	two members will be designated by Sempra Energy;

▪	two members will be appointed by TTI. If Sempra Energy acquires TTI’s interest in Oncor, the two board positions on the Oncor board of directors that TTI is entitled to appoint shall be eliminated, and the size of the Oncor board of directors will be reduced by two; and

▪

two members will be current or former officers of Oncor (the Oncor Officer Directors). In order for a current or former officer of Oncor to be eligible to serve as an Oncor Officer Director, such officer cannot have worked for Sempra Energy or any of its affiliates (excluding Oncor Holdings and Oncor) or any other entity with a direct or indirect ownership interest in Oncor or Oncor Holdings in the ten years prior to such officer being employed by Oncor. Oncor Holdings, at the direction of EFIH (a subsidiary of EFH, which will be a wholly owned indirect subsidiary of, and controlled by, Sempra Energy following the Merger), will have the right to nominate and/or seek the removal of the Oncor Officer Directors, with such nomination or removal subject to approval by a majority of the Oncor board of directors.

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(1)	Reflects losses on forward exchange contracts entered into to manage the foreign currency exchange rate risk of the CLF relative to the U.S. dollar, related to certain construction commitments that are denominated in CLF. The contracts settle based on anticipated payments to vendors, generally monthly, ending in July 2018.

(2)	The carrying value of our equity method investment is $12 million higher than the underlying equity in the net assets of the investee due to the remeasurement of our retained investment to fair value in 2014.

(3)	The carrying value of our equity method investment is $5 million higher than the underlying equity in the net assets of the investee due to guarantees, which we discuss below.

(4)	The carrying value of our equity method investment is $130 million higher than the underlying equity in the net assets of the investee due to equity method goodwill.

(5)	The carrying value of our equity method investment is $237 million and $190 million higher than the underlying equity in the net assets of the investee at December 31, 2017 and 2016, 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.

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(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 ETR.

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(1)	On November 15, 2017, IEnova completed the asset acquisition of PEMEX’s 50-percent interest in DEN, increasing its ownership percentage to 100 percent. At December 31, 2017, DEN is no longer an equity method investment.

(2)	On September 26, 2016, IEnova completed the acquisition of PEMEX’s 50-percent interest in IEnova Pipelines, increasing its ownership percentage to 100 percent, and on May 9, 2016, Sempra LNG & Midstream sold its 25-percent interest in Rockies Express. At December 31, 2016, IEnova Pipelines and Rockies Express are no longer equity method investments.

(3)	Except for our investments in South America and Mexico, there was no income tax recorded by the entities, as they are primarily domestic partnerships.

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(1)	Because the commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding as a reduction to the available unused credit.

(2)	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. No letters of credit were outstanding at December 31, 2017.

(3)	Sempra Energy guarantees Sempra Global’s obligations under the credit facility.

(4)	The facility 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. No letters of credit were outstanding at December 31, 2017.

▪	Each is a 5-year syndicated revolving credit agreement expiring in October 2020.

▪	Citibank N.A. serves as administrative agent for the Sempra Energy and Sempra Global facilities and JPMorgan Chase Bank, N.A. serves as administrative agent for the California Utilities combined facility.

▪	Each facility has a syndicate of 21 lenders. No single lender has greater than a 7-percent share in any facility.

▪	Sempra Energy, SDG&E and SoCalGas must maintain a ratio of indebtedness to total capitalization (as defined in each agreement) of no more than 65 percent at the end of each quarter. Each entity is in compliance with this and all other financial covenants under its respective credit facility at December 31, 2017.

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▪	Borrowings bear interest at benchmark rates plus a margin that varies with Sempra Energy’s credit ratings in the case of the Sempra Energy and Sempra Global lines of credit, and with the borrowing utility’s credit rating in the case of the California Utilities line of credit.

▪	The California Utilities’ obligations under their 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.

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(1)	Callable long-term debt not subject to make-whole provisions.

(2)	We discuss this lease in Note 15.

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(1)	Excludes capital lease obligations, build-to-suit lease, market value adjustments for interest rate swaps, discounts, premiums and debt issuance costs.

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(1)

Primarily due to fluctuation of the Mexican peso against the U.S. dollar. We record income tax expense (benefit) from the transactional effects of foreign currency and inflation because of significant appreciation (depreciation) of the Mexican peso. We also recognize gains (losses) in Other Income, Net, on the Consolidated Statements of Operations from foreign currency derivatives that are partially hedging Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova.

(2)	Related to operations in Mexico, Chile and Peru.

▪

Lower U.S. statutory corporate income tax rate: The change in the U.S. statutory corporate federal income tax rate from 35 percent to 21 percent resulted in income tax expense of $182 million for the year ended December 31, 2017 for Sempra Energy Consolidated because of the remeasurement of deferred income tax balances. SDG&E’s and SoCalGas’ impacts were primarily offset with adjustments to regulatory liabilities, however, they also recorded $28 million and $2 million of income tax expense, respectively, for the year ended December 31, 2017 associated with the TCJA.

▪

Deemed repatriation: The TCJA imposes a one-time tax for deemed repatriation of foreign undistributed earnings as determined under U.S. federal tax law. Under this provision, a U.S. shareholder must include in taxable income its pro-rata share of foreign undistributed earnings, which are taxed at 15.5 percent on cash or cash equivalents and 8 percent on cumulative other earnings. Sempra Energy Consolidated recorded deemed repatriation tax expense of $328 million. Based on our preliminary analysis, we currently anticipate using our existing NOLs to offset the deemed repatriation tax liability. In addition, we plan to repatriate these foreign undistributed earnings (estimated to be approximately $4 billion) that have now been taxed at the U.S. federal level. As a result, for the year ended December 31, 2017, we accrued $360 million of U.S. state and non-U.S. withholding tax expense on this expected future repatriation. This liability could change as a result of various factors, such as interpretation and clarification of the TCJA provisions, changes in foreign tax laws, foreign currency movements, the source of cash to be repatriated or adjustments to our provisional estimates, as we discuss below.

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▪	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

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(1)	In addition to the financial over tax basis differences in fixed assets, the amount also includes financial over tax basis differences in various interests in partnerships and certain subsidiaries.

(2)	At December 31, 2017 and 2016, includes $170 million and $234 million, respectively, recorded as a noncurrent asset and $2,767 million and $3,745 million, respectively, recorded as a noncurrent liability on the Consolidated Balance Sheets.

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(1)	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.

(2)	We have not recorded deferred income tax benefits on a portion of these NOLs and tax credits because we currently believe they will not be realized on a more-likely-than-not-basis, as discussed below.

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(1)	Includes temporary book and tax differences that are treated as flow-through for ratemaking purposes, as discussed above.

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▪	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 PBOP plans in the year in which the changes occur. Generally, those changes are reported in OCI and as a separate component of shareholders’ equity.

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▪	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.

▪	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.

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(1)

Excludes Mobile Gas plan. For Mobile Gas, which we deconsolidated on September 12, 2016, the health care cost trend rate assumed for next year for all retirees was 8.10 percent in 2015; the ultimate trend was 5.00 percent in 2015; and the year the rate reaches the ultimate trend was 2022 in 2015. For Chilquinta Energía, the health care cost trend rate assumed for next year, and the ultimate trend, was 3.00 percent in each of 2017, 2016 and 2015.

▪	38 percent domestic equity

▪	26 percent international equity

▪	18 percent long credit

▪	8 percent ultra-long duration government securities

▪	5 percent return-seeking credit

▪	5 percent real assets

▪	long-term cost

▪	variability and level of contributions

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▪	funded status

▪	a range of expected outcomes over varying confidence levels

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(1)	Excludes cash and cash equivalents of $13 million and accounts payable of $18 million.

(2)	Excludes cash and cash equivalents of $14 million and accounts payable of $24 million.

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(1)	Excludes cash and cash equivalents of $1 million and accounts payable of $1 million held in SDG&E PBOP plan trusts.

(2)	Excludes cash and cash equivalents of $4 million and accounts payable of $2 million held in SoCalGas PBOP plan trusts.

(3)	Excludes cash and cash equivalents of $5 million and accounts payable of $3 million at Sempra Energy Consolidated.

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(1)	Excludes cash and cash equivalents of $1 million and accounts payable of $1 million held in SDG&E PBOP plan trusts.

(2)	Excludes cash and cash equivalents of $4 million and accounts payable of $4 million held in SoCalGas PBOP plan trusts.

(3)	Excludes cash and cash equivalents of $5 million and accounts payable of $5 million at Sempra Energy Consolidated.

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▪	non-qualified stock options

▪	incentive stock options

▪	restricted stock awards

▪	restricted stock units

▪	stock appreciation rights

▪	performance awards

▪	stock payments

▪	dividend equivalents

▪

Non-Qualified Stock Options: Options to purchase common stock 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 RSU awards generally vest in Sempra Energy common stock at the end of three-year (for awards granted during or after 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 EPS. The comparative market indices for the awards that vest based on total return to shareholders are the 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 targets for awards that vest based on EPS growth.

◦	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 RSUs may be issued.

◦	For awards granted during or after 2014, up to an additional 100 percent of the granted RSUs may be issued if total return to shareholders or EPS growth exceeds target levels.

◦

For awards granted in 2015 and 2016, and certain awards granted in 2017, 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 RSUs 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.

▪	Other Performance-Based Restricted Stock Units: RSUs 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.

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◦	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.

▪	Service-Based Restricted Stock Units: RSUs may also be service-based; these generally vest at the end of three-year (for awards granted during or after 2015) or four-year service periods.

▪	Restricted Stock Awards: RSAs are solely service-based and generally vest at the end of four years of service. Accelerated vesting of RSAs may occur upon eligibility for retirement. Holders of RSAs have full voting rights.

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▪	$9 million in 2017

▪	$8 million in 2016

▪	$12 million in 2015

(1)

Each RSU represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For all performance-based RSUs, 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 RSUs may be issued if Sempra Energy exceeds target performance conditions.

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▪

The California Utilities use natural gas and electricity derivatives, 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 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, Sempra LNG & Midstream and Sempra Renewables 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 and storage, and power generation. 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 may also use natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its Mexican distribution

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▪	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 and GHG allowances.

(1)	Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.

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(1)	In the first quarter of 2018, we entered into foreign currency derivatives with notional amounts totaling $650 million that expire between December 2018 and January 2019.

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(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.

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(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.

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(1)	There was no hedge ineffectiveness in 2016 or 2015. 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.

(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.

(2)	There was $5 million, $4 million and $2 million of losses from ineffectiveness related to these cash flow hedges in 2017, 2016 and 2015, respectively.

(3)	There was negligible hedge ineffectiveness related to these cash flow hedges in 2017, 2016 and 2015.

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▪

Nuclear decommissioning trusts reflect the assets of SDG&E’s NDT, 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. 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 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 in “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). These investments in marketable securities were negligible at both December 31, 2017 and 2016.

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(1)	Excludes cash balances and cash equivalents.

(2)	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.

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(1)	Excludes cash balances and cash equivalents.

(2)	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.

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(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.

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(1)	Excluding accumulated interest outstanding of $29 million and $17 million at December 31, 2017 and 2016, respectively, and excluding foreign currency translation of $35 million on a Mexican peso-denominated loan at December 31, 2017.

(2)	Before reductions for unamortized discount (net of premium) and debt issuance costs of $143 million and $109 million at December 31, 2017

(3)	Level 3 instruments include $295 million and $305 million at December 31, 2017 and 2016, respectively, related to Otay Mesa VIE.

(4)	Before reductions for unamortized discount and debt issuance costs of $45 million at December 31, 2017 and 2016, respectively, and excluding capital lease obligations of $732 million and $240 million at December 31, 2017 and 2016, respectively.

(5)	Before reductions for unamortized discount and debt issuance costs of $24 million and $27 million at December 31, 2017 and 2016, respectively, and excluding capital lease obligations of $1 million at December 31, 2017.

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(1)	At measurement date of September 26, 2016, immediately prior to acquiring a 100-percent ownership interest in IEnova Pipelines.

(2)	At measurement date of September 29, 2016.

(3)	At measurement date of June 30, 2017. At December 31, 2017, TdM has a carrying value of $78 million, reflecting subsequent business activity, and is classified as held for sale.

(4)	At measurement date of March 29, 2016. On May 9, 2016, Sempra LNG & Midstream sold its equity interest in Rockies Express.

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(1)	Includes average fully vested RSUs held in our Deferred Compensation Plan of 609 in 2017, 568 in 2016 and 491 in 2015. These fully vested RSUs 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.

(2)	Due to market fluctuations of both Sempra Energy stock and the comparative indices used to determine the vesting percentage of our total shareholder return performance-based RSUs, which we discuss in Note 8, dilutive RSUs may vary widely from period-to-period.

(3)	Our board of directors has the discretion to determine the payment and amount of future dividends.

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(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 or units from long-term incentive plan participants who elect to sell to us a sufficient number of vested RSAs or RSUs to meet minimum statutory tax withholding requirements.

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▪	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 (discussed in Note 14) proceeding then in effect (collectively, SONGS return on rate base)

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(1)	Maturity dates are 2018-2048.

(2)	Maturity dates are 2018-2064.

(1)	Excludes securities that are held to maturity.

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(1)	Regulatory assets earning a rate of return.

(2)	At December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $63 million. At December 31, 2017 and 2016, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $118 million and $85 million, respectively.

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▪

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. We discuss these fixed-price contracts and other derivatives further in Note 9.

▪

Regulatory assets arising from the 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. Pursuant to the Revised Settlement Agreement, rate recovery of SONGS costs remaining as a regulatory asset as of the Cessation Date will cease. Under the Utility Shareholder Agreement, SDG&E recorded a receivable from Edison in lieu of amounts SDG&E would have collected from ratepayers. We discuss these matters further in Note 13.

▪

Regulatory assets for CPUC-related costs for wildfire litigation are costs in excess of liability insurance coverage and amounts recovered from third parties. In December 2017, the CPUC issued a final decision, denying SDG&E’s request to recover these costs. In 2017, SDG&E wrote off the wildfire regulatory asset resulting in a charge of $351 million, as we discuss in Note 15 in “SDG&E – 2007 Wildfire Litigation and Net Cost Recovery Status.”

▪

Deferred income taxes refundable/recoverable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Mexico expect to refund/recover net regulatory liabilities/assets related to deferred income taxes over the lives of the assets that give rise to the related accumulated deferred income tax balances. Regulatory assets include certain income tax benefits associated with flow-through repair allowance deductions, which we discuss further below. In 2017, as a result of the TCJA, lowering the U.S. statutory corporate federal income tax from 35 percent to 21 percent resulted in excess deferred income tax balances that we expect to refund to ratepayers in accordance with the IRS normalization rules and as determined by the CPUC and the FERC. We discuss the TCJA and the impacts on Sempra Energy, SDG&E and SoCalGas in more detail in Note 6.

▪	Regulatory assets/liabilities related to pension and other postretirement benefit plan obligations are offset by corresponding liabilities/assets and are being recovered in rates as the plans are funded.

▪	The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made.

▪	Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs.

▪	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 1 year to 10 years for SDG&E and from 3 years to 8 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. We discuss environmental issues further in Note 15.

▪	The regulatory asset related to the legacy meters removed from service and replaced under the Smart Meter Program is their undepreciated value. SDG&E has fully recovered this asset 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 52-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.

▪

Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs, including commodity costs. Depreciation and return on rate base may also be included in certain accounts. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. Absent balancing account treatment, variations in covered costs, such as the cost of fuel supply and certain O&M costs, from amounts approved by the CPUC would increase volatility in utility earnings. Balancing account treatment eliminates the volatility in earnings that would otherwise result from variances in the covered costs compared to the authorized amounts.

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▪	net revenue changes;

▪	mandatory tax law, tax accounting, tax procedural, or tax policy changes; and

▪	elective tax law, tax accounting, tax procedural, or tax policy changes.

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(1)	Excludes amounts related to the LNG purchase agreement discussed below.

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▪	Long-term contracts: 43 percent (of which 37 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: 1 percent

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(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.

(2)	Includes $5.4 billion of expected payments under purchase agreements accounted for as operating leases at SDG&E, comprising renewable energy PPAs for which there are no future minimum operating lease payments.

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(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 $13 million in Current Portion of Long-Term Debt and $718 million in Long-Term Debt on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets at December 31, 2017. The remaining present value of net minimum lease payments of $550 million will be recorded as a capital lease obligation when construction of the power plant facility is completed and delivery of contracted power commences, which is scheduled to occur in June 2018.

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▪	$72 million for infrastructure improvements for natural gas and electric transmission and distribution operations;

▪	$35 million for the engineering, material procurement and construction costs primarily associated with the Sycamore-Peñasquitos Transmission Project; and

▪	$10 million related to spent fuel management at SONGS.

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(1)	In cases of non-wholly owned affiliates, includes only our share.

(1)	There may be ongoing compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring.

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(1)	Sites for which we have been identified as a PRP.

(2)	Includes $9 million, $1 million and $8 million classified as current liabilities, and $20 million, $3 million and $16 million 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 environment mitigation.

(4)	Does not include SoCalGas’ liability for environmental matters for the natural gas leak at the Aliso Canyon natural gas storage facility. We discuss matters related to the leak above in “Legal Proceedings – SoCalGas – Aliso Canyon Natural Gas Storage Facility Gas Leak.”

▪	SDG&E provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.

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▪	SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California.

▪	Sempra South American Utilities develops, owns and operates, or holds interests in, electric transmission, distribution and generation infrastructure in Chile and Peru.

▪

Sempra Mexico develops, owns and operates, or holds interests in, natural gas, electric, LNG, LPG, ethane and liquid fuels infrastructure, and has marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico. In February 2016, management approved a plan to market and sell the TdM natural gas-fired power plant located in Mexicali, Baja California, as we discuss in Note 3.

▪	Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy generation facilities serving wholesale electricity markets in the U.S.

▪

Sempra LNG & Midstream develops, owns and operates, or holds interests in, a terminal for the import and export of LNG and sale of natural gas, and natural gas pipelines, storage facilities and marketing operations, all within the U.S. In September 2016, Sempra LNG & Midstream sold EnergySouth, the parent company of Mobile Gas and Willmut Gas, and in May 2016, sold its 25-percent interest in Rockies Express. Sempra LNG & Midstream 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. We discuss these divestitures in Note 3.

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(1)	Revenues for reportable segments include intersegment revenues of $7 million, $74 million, $103 million and $266 million for 2017, $6 million, $76 million, $102 million and $180 million for 2016, and $9 million, $75 million, $101 million and $192 million for 2015 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG & Midstream, respectively.

(2)	After preferred dividends.

(3)	Includes net PP&E and investments.

(4)	Amounts are based on where the revenue originated, after intercompany eliminations.

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(1)	Earnings per share are computed independently for each of the quarters and therefore may not sum to the total for the year.

(2)	In the quarter ended December 31, 2017, the total weighted-average number of potentially dilutive securities was 0.8 million. However, these securities were not included in the computation of U.S. GAAP losses per common share since to do so would have decreased the loss per share.

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▪	senior to our common stock, including our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise;

▪	junior to our existing and future indebtedness and other liabilities; and

▪	structurally subordinated to any existing and future indebtedness and other liabilities of our subsidiaries and capital stock of our subsidiaries held by third parties.

(1)	Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 25 basis points.

(2)	Bears interest at a rate per annum equal to the 3-month LIBOR rate, plus 50 basis points.

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(1)	As adjusted for the retrospective adoption of ASU 2016-15, which we discuss in Note 2.

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▪	$56 million, $23 million and $3 million of gains on dedicated assets in support of our executive retirement and deferred compensation plans in 2017, 2016 and 2015, respectively; and

▪	$50 million and $(28) million net gains (losses) primarily from the settlement of foreign currency derivatives to hedge Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova in 2017 and 2016, respectively.

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▪	Issue 1 – debt prepayment or debt extinguishment costs (a negligible amount in each year presented below)

▪	Issue 6 – distributions received from equity method investments

(1)	Prior to adoption of ASU 2016-15, because of its nature as a holding company, Sempra Energy Parent classified dividends received from subsidiaries as an investing cash flow.

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(a)	“Account” or “Accounts” shall mean a Participant’s Deferral Account and/or Employer Matching Account (including any Subaccounts thereunder).

(b)	“Administrator” shall mean the individual(s) designated by the Committee (who need not be a member of the Committee) to handle the day-to-day Plan administration. If the Committee does not make such a designation, the Administrator shall be the most senior officer of Human Resources of Sempra Energy.

(c)	“Affiliate” has the meaning ascribed to such term in Rule 12b-2 promulgated under the Exchange Act.

(d)

“Base Salary” shall mean, with respect to any Participant, the Participant’s annual base salary, excluding bonus, incentive and all other remuneration for services rendered to the Company, prior to reduction for any salary contributions to a plan established pursuant to Section 125 of the Code or qualified pursuant to Section 401(k) of the Code and prior to reduction for deferrals under this Plan.

(e)	“Beneficial Owner” has the meaning set forth in Rule 13d-3 under the Exchange Act.

(f)	“Beneficiary” or “Beneficiaries” shall mean the person or persons, including a trustee, personal representative or other fiduciary, last designated in writing by a Participant to receive the benefits specified hereunder in the event of the Participant’s death in accordance with Section 9.4.

(g)	“Board of Directors” or “Board” shall mean the Board of Directors of Sempra Energy.

(h)	“Bonus” shall mean the annual cash incentive award earned by a Participant under the Company’s short-term incentive plans and other special cash payments or cash awards that may be granted by the Company from time to time to the extent that such other special cash payments or cash awards are permitted by the Committee to be deferred under the Plan.

(i)	“Change in Control” shall be deemed to have occurred when any event or transaction described in paragraph (1), (2), (3) or (4) occurs, subject to paragraph (5):

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(j)	“Code” shall mean the Internal Revenue Code of 1986, as amended, and all applicable rules and regulations thereunder

(k)	“Committee” shall mean the compensation committee of the Board of Directors.

(l)

“Company” shall mean Sempra Energy and any successor corporations. The term “Company” shall also include each corporation which is a member of a controlled group of corporations (within the meaning of Section 414(b) of the Code) of which Sempra Energy is a component member if the Committee provides that such corporation shall participate in the Plan and such corporation’s governing board of directors adopts the Plan. Any corporation described in the preceding sentence that participates in the Plan immediately prior to the Effective Date shall be deemed to participate in the Plan and to have adopted the Plan without any further action of either such corporation or Sempra Energy, subject to the terms and conditions of the Plan.

(m)	“Compensation” shall mean, with respect to a Participant, the following:

(n)

“Deferral Account” shall mean the bookkeeping account maintained under the Plan for each Participant that is credited with amounts equal to the portion of the Participant’s Compensation that he elects to defer pursuant to Section 3.1, debited by amounts equal to all distributions to and withdrawals made by the Participant and/or his Beneficiary and adjusted for investment earnings and losses pursuant to Article V. The Deferral Account may be further subdivided into Subaccounts as determined by the Committee or the Administrator.

(o)	“Deferral Election Form” shall mean the form designated by the Committee or the Administrator for purposes of making deferrals under Section 3.1.

(p)	“Director” shall mean an individual who is a non-employee member of the Board.

(q)	“Disability” or “Disabled” means, with respect to a Participant, that the Participant:

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(r)	“Distributable Amount” of a Participant’s Subaccounts with respect to a Plan Year shall mean the sum of the vested balance of the Subaccount in a Participant’s Deferral Account and Employer Matching Account with respect to such Plan Year.

(s)	“Effective Date” shall mean November 9, 2017.

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(u)

“Elective Phantom Share Amount” ” shall mean, with respect to an initial or annual equity award by Sempra Energy to a Participant who is a Director, which the Director may elect to receive in the form of (1) an award of Restricted Stock Units, or (2) an amount credited to such Participant’s Deferral Account in the Sempra Energy Stock Fund, the dollar value designated by the Board for such equity award that is used for purposes of determining the number of Restricted Stock Units subject to such award, or the amount to be credited to such Participant’s Deferral Account. In the case of a Director who first becomes a Director by reason of appointment or election as a Director, any such initial equity award shall be granted on the tenth New York Stock Exchange trading day after such appointment or election.

(v)

“Eligible Individual” shall mean those individuals selected by the Committee from (1) those employees of the Company who either (A) are Executive Officers or (B) have Base Salary for a calendar year that is at least $170,000, as adjusted by the Committee from time to time and (2) those Directors who are not employees of the Company. The Committee may, in its sole discretion, select such other individuals to participate in the Plan who do not otherwise meet the foregoing criteria. Except as otherwise provided by the Committee or the Administrator, an Eligible Individual who is not a Director shall first become eligible to participate in the Plan on first day of the first calendar quarter that occurs at least thirty (30) days after the Eligible Individual commences employment in a covered category as set forth in clause (A) or (B) of this Section 1.2(v) (and, to the extent applicable, is selected as an Eligible Individual under the Plan). A Director shall become a Participant in the Plan in accordance with Section 2.2 on the date of such Director’s appointment or election as a Director.

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(w)	“Employer Matching Account” shall mean the bookkeeping account maintained under the Plan for each Participant that is credited with an amount equal to the Employer Matching Contribution, if any, debited by amounts equal to all distributions to and withdrawals made by the Participant and/or his Beneficiary and adjusted for investment earnings and losses pursuant to Article V.

(x)	“Employer Matching Contributions” shall mean the employer matching contribution made to the Plan pursuant to Section 3.3.

(y)	“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended, and all applicable rules and regulations thereunder.

(z)	“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended, and the applicable rules and regulations thereunder.

(aa)	“Executive Officer” shall mean an employee of the Company who (i) is designated by the Board as an executive officer of Sempra Energy pursuant to Rule 3b-7 of the Exchange Act, (ii) participates in the Sempra Energy Supplemental Executive Retirement Plan, or (iii) who is otherwise designated as an Executive Officer by the Committee.

(bb)	“401(k) Plan” shall mean the Sempra Energy Savings Plan, as in effect from time to time, maintained by Sempra Energy under Section 401(k) of the Code.

(cc)	“Manager” shall mean an employee of the Company who is an Eligible Individual, other than an Executive Officer or a Director.

(dd)	“Measurement Fund” shall mean one or more of the investment funds selected by the Committee pursuant to Section 4.1.

(ee)

“Moody’s Plus Rate” shall mean the Moody’s Rate (as defined below) plus the greater of (1) 10% of the Moody’s Corporate Bond Yield Average – Monthly Average Corporates as published by Moody’s Investors Service, Inc. (or any successor) or (2) one percentage point per annum. The Moody’s Rate for a month means the average of the daily Moody’s Corporate Bond Yield Average – Monthly Average Corporates for the applicable month. Unless otherwise designated by the Committee, the “applicable month” shall be the month of June in the prior year.

(ff)	“Nonelective Phantom Share Amount” shall mean the dollar amount designated by the Board for purposes of subsection 3.1(f) to be invested in the Sempra Energy Stock Fund.

(gg)	“Participant” shall mean any Eligible Individual who becomes a Participant in accordance with Article II and who has not received a complete distribution of the amounts credited to his Accounts.

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(hh)	“Payroll Date” shall mean, with respect to any Participant, the date on which he would otherwise be paid Compensation.

(ii)	“Payment Date” shall mean the business day determined by the Committee or the Administrator that is on or within thirty (30) calendar days after one of the following dates as designated by the Participant in his distribution form election with respect to a Plan Year:

(jj)

“Person” means any person, entity or “group” within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, except that such term shall not include (1) Sempra Energy or any of its Affiliates, (2) a trustee or other fiduciary holding securities under an employee benefit plan of Sempra Energy or any of its Affiliates, (3) an underwriter temporarily holding securities pursuant to an offering of such securities, (4) a corporation owned, directly or indirectly, by the shareholders of Sempra Energy in substantially the same proportions as their ownership of stock of Sempra Energy, or (5) a person or group as used in Rule 13d-1(b) under the Exchange Act.

(kk)	“Plan” shall mean the Sempra Energy Employee and Director Savings Plan set forth herein, as amended from time to time.

(ll)	“Plan Year” shall mean the twelve (12) consecutive month period beginning on each January 1 and ending on each December 31.

(mm)	“QDRO” shall mean a domestic relations order that constitutes a “qualified domestic relations order” within the meaning of the Code or ERISA.

(nn)	“Restricted Stock Units” shall mean restricted stock units granted to a Participant under the Sempra Energy 2008 Long Term Incentive Plan, Sempra Energy 2013 Long-Term Incentive Plan, and any successor plan(s) thereto.

(oo)	“Rule 16b-3” shall mean that certain Rule 16b-3 under the Exchange Act, as such Rule may be amended from time to time.

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(pp)	“Scheduled Withdrawal Date” shall be in January in the year elected by the Participant for an in-service withdrawal elected in accordance with subsection 3.2(c), as set forth on the election forms for such Plan Year. If the day elected by the Participant is not a business day, the Scheduled Withdrawal Date shall be deemed to be the next following business day.

(qq)	“Sempra Energy Stock Fund” shall mean the Measurement Fund in which investment earnings and losses parallel the investment return on the common stock of Sempra Energy.

(rr)	“Separation from Service” shall mean, with respect to a Participant, the Participant’s “separation from service,” as defined in Treasury Regulation Section 1.409A-1(h).

(ss)	“SERP Lump Sum” shall mean the lump sum retirement benefit that would be payable to an Executive Officer who is a Plan Participant under either the Sempra Energy Supplemental Executive Retirement Plan or the Sempra Energy Excess Cash Balance Plan.

(tt)	“Specified Employee” shall mean a specified employee determined in accordance with the requirements of Section 409A of the Code.

(uu)	“Subaccount” or “Subaccounts” shall mean the subaccount or subaccounts maintained with respect to a Participant’s Deferral Account or Employer Matching Account.

(vv)	“Valuation Date”, with respect to the Measurement Funds that are available under the 401(k) Plan, shall have the same meaning as under the 401(k) Plan. For purposes of the Measurement Fund based on Moody’s Plus Rate, “Valuation Date” shall mean the last day of the calendar month.

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(a)

General Rule. Each Eligible Individual may defer Compensation for a Plan Year by filing with the Committee or the Administrator a Deferral Election Form for such Plan Year that conforms to the requirements of this Section 3.1, no later than the last day of the applicable Election Period for such Plan Year, and such deferral election shall become irrevocable on the last day of the applicable Election Period for such Plan Year (or such later date permitted by the Committee or the Administrator consistent with the requirements of Section 409A of the Code). Unless otherwise provided by the Committee, an Eligible Individual who first becomes eligible to participate in the Plan during a Plan Year may elect to defer Compensation for such Plan Year; provided, however, that any such election to defer Compensation for such Plan Year must be filed during the Election Period prior to the effective date of such election, shall be irrevocable when made, and shall be effective only for Compensation that constitutes compensation for services performed during periods during the Plan Year beginning after the effective date of such election. Notwithstanding the previous sentence, if an Eligible Individual’s Bonus (or portion thereof) is a performance-based compensation within the meaning of Section 409A of the Code, the Committee or the Administrator may permit such Eligible Individual to file an election to defer such Bonus (or such portion thereof), or change such Eligible Individual’s prior election to defer such Bonus (or such portion thereof), no later than the date that is six (6) months before the end of the performance period over which such services are to be performed, under the terms and conditions that may be specified by the Committee or the Administrator, in accordance with Section 409A of the Code, and such deferral election shall become irrevocable on the date that is six (6) months before the end of the performance period.

(b)	Special Rules. Notwithstanding the above, the following restrictions apply to deferrals of certain elements of Compensation:

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(c)

Deferral Amounts. The amount of Base Salary or Bonus that a Participant may elect to defer for a Plan Year is such Base Salary or Bonus earned on or after the time at which the Participant elects to defer for such Plan Year in accordance with subsection 3.1(a), and that is earned during the Plan Year to which the deferral election relates (other than with respect to subsequent deferrals of previously deferred amounts or other amounts that are treated as subsequent deferrals for purposes of Section 409A of the Code). In no event shall a Participant be permitted to defer any amount of Compensation earned prior to the date of the deferral election or attributable to services performed prior to the date of the deferral election (other than with respect to subsequent deferrals of previously deferred amounts or other amounts that are treated as subsequent deferrals for purposes of Section 409A of the Code or as permitted under the Plan relating to performance-based compensation).

(d)	Duration of Deferral Election.

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(e)	Elections. Any Eligible Individual who does not elect to defer Compensation during his Election Period for a Plan Year may subsequently participate in the Plan in accordance with the terms and conditions of the Plan.

(f)

Nonelective Compensation Deferrals for Directors. The Board may determine from time to time whether deferrals of Nonelective Phantom Share Amounts shall be credited to the Deferral Accounts of one or more Participants who are Directors. The Board shall designate the Nonelective Phantom Share Amounts and any conditions under which a Director shall be entitled to have Nonelective Phantom Share Amounts credited to his Deferral Account. A Nonelective Phantom Share Amount credited to a Director’s Deferral Account shall constitute compensation for services to be performed by the Director during a calendar quarter, and the Nonelective Phantom Share Amount for such calendar quarter shall be credited to the Director’s Deferral Account on the first New York Stock Exchange trading day of such calendar quarter; provided, however, that, in the case of a Director who first becomes a Director by reason of appointment or election as a Director, for purposes of the calendar quarter during which such appointment or election occurs, such Director’s Deferral Account shall be credited with a prorated portion of the Nonelective Phantom Share Amount for the portion of such calendar quarter (if any), commencing on the tenth New York Stock Exchange trading day after such Director’s appointment or election and ending on the last day of the calendar quarter, and any such prorated portion of the Nonelective Phantom Share Amount shall constitute compensation for services to be performed by the Director during the period commencing on such tenth New York Stock Exchange trading day and ending on the last day of such calendar quarter and shall be determined based on the portion of such calendar quarter that comprises such period and such prorated portion of the Nonelective Phantom Share Amount shall be credited to the Director’s Deferral Account on the New York Stock Exchange trading day next following the last day of such calendar quarter. The service period for a Nonelective Phantom Share Amount (or a prorated Nonelective Phantom Share Amount) shall be the calendar quarter, or portion thereof, during which the Director performs services for which such Nonelective Phantom Share Amount (or prorated Phantom Share Amount) constitutes compensation. Such Nonelective Phantom Share Amounts shall be deferred on a nonelective basis. An eligible Participant must file the appropriate Deferral Election Form with respect to the Nonelective Phantom Share Amounts that constitute compensation for services performed during periods during the Plan Year beginning after the effective date of such election, for purposes of electing the Payment Date and the form of distribution of such Nonelective Phantom Share Amounts, no later than the last day of the applicable Election Period for the Plan Year during which such Nonelective Phantom Share Amounts are credited, and such deferral election shall become irrevocable on the last day of the applicable Election Period for such Plan Year. The Committee or the Administrator shall permit such a Participant who first becomes a Participant during a Plan Year to have his first Election Period with

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(g)

Termination of Participation and/or Deferrals. If the Committee or the Administrator determines in good faith that a Participant no longer qualifies as a Director or a member of a select group of management or highly compensated employees, as membership in such group is determined in accordance with Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA, the Committee or the Administrator shall have the right, in its sole discretion and only for purposes of preserving the Plan’s exemption from Title I of ERISA, to prevent the Participant from making deferral elections for future Plan Years.

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(a)

General Rule. Each Participant shall make a separate distribution election with respect to each Plan Year for which such Participant elects to defer Compensation in accordance with Section 3.1. In the case of each Participant who is a Director, such Participant shall make a separate distribution election with respect to each Plan Year without regard to whether such Participant elects to defer Compensation in accordance with Section 3.1. A Participant’s distribution election with respect to a Plan Year shall apply to: (1) the Subaccount in his Deferral Account to which shall be credited the amount equal to the portion of his Compensation earned during such Plan Year that he elects to defer pursuant to Section 3.1, (2) in the case of a Participant who is a Director, the Subaccount in his Deferred Account to which shall be credited any Elective Phantom Share Amounts for equity awards granted during such Plan Year that he elects to defer pursuant to Section 3.1, and the Subaccount in his Deferral Account to which shall be credited any Nonelective Phantom Share Amounts during such Plan Year pursuant to subsection 3.1(f), and (3) the Subaccount in his Employer Matching Account to which shall be credited the amount equal to the Employer Matching Contribution for such Plan Year. A Participant may elect any Payment Date described in subsection 1.2(ii), and may elect distribution in the normal form, as described in paragraph 7.1(a)(1), or an optional form described in paragraph 7.1(a)(2). Such Payment Date and distribution form elections shall be made on such Participant’s Deferral Election Form during the Election Period for which such Participant elects to defer Compensation under Section 3.1 for such Plan Year, and such Payment Date and distribution form elections with respect to such Plan Year shall be irrevocable, except as provided in subsection 3.2(b). In the event a Participant fails to elect a Payment Date for his Distributable Amount with respect to a Plan Year, his Payment Date for his Distributable Amount with respect to such Plan Year shall be the date described in paragraph 1.2(ii)(1). In the event a Participant fails to make a distribution form election for his Distributable Amount with respect to a Plan Year, his Distributable Amount with respect to such Plan Year shall be distributed in the normal form, as described in paragraph 7.1(a)(1) in the event of his Separation from Service or Disability, except as provided in subsection 3.2(b). Except as provided in subsection 3.2(b), a Participant’s distribution for his Distributable Amount with respect to a Plan Year shall be made or commence on such Participant’s Payment Date.

(b)	Changes to Distribution Form Election. Subject to subsection 3.2(e), a Participant may change his distribution form election for his Distributable Amount with respect to a Plan Year in accordance with this subsection 3.2(b) as follows:

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(c)

Election of Scheduled Withdrawal Date. A Participant may elect a Scheduled Withdrawal Date with respect to his deferrals of Compensation (the “Withdrawal Amount”) with respect to a Plan Year. Such election of a Scheduled Withdrawal Date for such Participant’s Withdrawal Amount with respect to a Plan Year shall be made by such Participant during the Election Period for which such Participant elects to defer Compensation under Section 3.1 for such Plan Year, and such election of a Scheduled Withdrawal Date shall be irrevocable, except as provided in subsection 3.2(d). A Participant may make separate Scheduled Withdrawal Date elections for his deferrals of Compensation with respect to different Plan Years. A Participant’s Withdrawal Amount with respect to a Plan Year shall be credited to Subaccounts under such Participant’s Accounts for such Plan Year. A Participant shall not be required to elect a Scheduled Withdrawal Date with respect to his deferrals of Compensation for a Plan Year and, if a Participant fails to make an election of a Scheduled Withdrawal Date for a Plan Year, no Scheduled Withdrawal Date shall apply with respect to his deferrals of Compensation for such Plan Year. For purposes of the Plan, the deferrals of Compensation included as part of the Withdrawal Amount (i) shall be adjusted for investment earnings and losses in the case of elections made on or after November 10, 2016 and (ii) shall be adjusted for investment losses (but not investment earnings) in the case of elections made prior to November 10, 2016.

(d)

Change of Scheduled Withdrawal Date. Subject to subsection 3.2(e), if a Participant elected a Scheduled Withdrawal Date with respect to his deferrals of Compensation with respect to a Plan Year in accordance with subsection 3.2(c), such Participant may change such Scheduled Withdrawal Date for the Withdrawal Amount with respect to such Plan Year by electing a new Scheduled Withdrawal Date for the Withdrawal Amount with respect to such Plan Year that is not less than five (5) years later than the Scheduled Withdrawal Date previously elected by such Participant for such Plan Year. A Participant who has not elected a Scheduled Withdrawal Date for his deferrals of Compensation in accordance with subsection 3.2(c) for a Plan Year may not subsequently elect a Scheduled Withdrawal Date for his deferrals of Compensation for such Plan Year. A Participant may make only one change to the Scheduled Withdrawal Date with respect to each Plan Year under this subsection 3.2(d).

(e)	Limitation on Distribution Changes. A Participant’s election to change his distribution form election with respect to a Plan Year under subsection 3.2(b), or change of a Scheduled Withdrawal Date with respect to a Plan Year under subsection 3.2(d), shall be subject to the following limitations:

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(a)	The Company shall make an Employer Matching Contribution for each payroll date during a Plan Year, on behalf of each Participant who is employed by the Company on such payroll date, who has been employed by the Company for at least one (1) year as of such payroll date, and who makes deferrals of Base Salary and/or Bonus under Article III, in an amount equal to:

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(b)	The Employer Matching Contribution for a Plan Year shall be credited to a Participant’s Employer Matching Account in the manner determined by the Committee or the Administrator.

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(a)

Election of Measurement Funds. In the manner designated by the Committee or the Administrator, Participants may elect one or more Measurement Funds to be used to determine the additional amounts to be credited to their Accounts. Although the Participant may designate the available Measurement Funds that will be used to determine additional amounts to be credited to their Accounts, neither the Committee nor the Administrator shall be bound to make actual investments in such Measurement Funds based on the Participant’s election. If the Committee designates a substitute Measurement Fund for a Participant (without regard to the Participant’s election), the substitute Measurement Fund must provide the Participant with an investment opportunity reasonably comparable to the original Measurement Funds elected by the Participant, as determined by the Committee in its sole discretion. The Committee shall select from time to time, in its sole discretion, the Measurement Funds to be available under the Plan.

(b)

No Actual Investment. Notwithstanding any other provision of this Plan that may be interpreted to the contrary, the Measurement Funds are to be used for measurement purposes only, and a Participant’s election of any such Measurement Fund, the allocation to his Accounts thereto, the calculation of additional amounts and the crediting or debiting of such amounts to a Participant’s Accounts shall not be considered or construed in any manner as an actual investment of his Accounts in any such Measurement Fund. In the event that the Committee, the Administrator, or the trustee, as applicable, in its own discretion, decides to invest funds in any or all of the Measurement Funds, no Participant shall have any rights in or to such investments themselves. Without limiting the foregoing, a Participant’s Accounts shall at all times be a bookkeeping entry only and shall not represent any investment made on his behalf by the Company. The Participant shall at all times remain an unsecured creditor of the Company

(a)	Participants.

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(b)	Continuing Investment Elections. Participants who have had a Separation From Service but not yet commenced distributions under Article VII or Participants or Beneficiaries who are receiving installment payments may continue to make investment elections as permitted under subsection 4.2(a) except as otherwise determined by the Committee.

(a)

Any Participant or Beneficiary who is subject to Section 16 of the Exchange Act shall have his Measurement Fund elections under the Plan subject to the requirements of the Exchange Act, as interpreted by the Committee. Any such Participant or Beneficiary who either (i) transferred amounts from another available Measurement Fund under the Plan into the Sempra Energy Stock Fund or (ii) transferred any amounts from the Sempra Energy Stock Fund to another available Measurement Fund under the Plan may not make an election with the opposite effect under this Plan or any other Company-sponsored plan until six (6) months and one (1) day following the original election.

(b)

Notwithstanding any other provision of the Plan or any rule, instruction, election form or other form, the Plan and any such rule, instruction or form shall be subject to any additional conditions or limitations set forth in any applicable exemptive rule under Section 16 of the Exchange Act (including any amendment to Rule 16b‑3) that are requirements for the application of such exemptive rule. To the extent permitted by applicable law, such Plan provision, rule, instruction or form shall be deemed amended to the extent necessary to conform to such applicable exemptive rule.

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(a)

The Committee or the Administrator shall establish and maintain a Deferral Account, and an Employer Matching Account for each Participant under the Plan. Each Participant’s Accounts shall be divided into separate Subaccounts in accordance with Section 5.2. Each such Subaccount shall be further divided into separate investment fund Subaccounts, each of which corresponds to a Measurement Fund elected by the Participant pursuant to Section 4.2. In addition, Participants’ Deferral Accounts shall be further divided into Subaccounts consisting of deferred Restricted Stock Units, Elective Phantom Share Amounts, and Nonelective Phantom Share Amounts. A separate Subaccount shall be maintained for each deferral of Restricted Stock Units, Nonelective Phantom Share Amount and Elective Phantom Share Amount.

(b)

The performance of each elected Measurement Fund (either positive or negative) shall be determined by the Committee or the Administrator, in its reasonable discretion, based on the performance of the Measurement Funds themselves. A Participant’s Accounts shall be credited or debited on each Valuation Date, as determined by the Committee or the Administrator in its reasonable discretion, based on the performance of each Measurement Fund selected by the Participant as though (i) a Participant’s Accounts were invested in the Measurement Fund(s) selected by the Participant, in the percentages applicable to such period, as of the close of business on the first business day of such period, at the fair market value on such date; (ii) the portion of the Participant's Compensation that was actually deferred pursuant to Section 3.1 during any period were invested in the Measurement Fund(s) selected by the Participant, in the percentages applicable to such period, no later than the close of business on the first business day after the day on which such amounts are actually deferred from the Participant’s Compensation, at the fair market value on such date; and (iii) any withdrawal or distribution made to a Participant that decreases such Participant’s Accounts ceased being invested in the Measurement Fund(s), in the percentages applicable to such period, no earlier than one (1) business day prior to the distribution, at the fair market value on such date. The Participant’s Employer Matching Contribution for a Plan Year shall be credited to his Employer Matching Account for purposes of this subsection 5.1(b), in the manner determined on the first day of the Election Period for such Plan Year, as determined by the Committee or the Administrator.

5.2	Subaccounts.

(a)

The Committee or the Administrator shall establish and maintain, with respect to a Participant’s Deferral Account, a Subaccount with respect to each Plan Year, to which shall be credited the amount equal to the portion of the Participant’s Compensation earned during such Plan Year that he elects to defer pursuant to Section 3.1, debited by amounts equal to distributions to and withdrawals made by the Participant and/or his Beneficiary and adjusted for investment earnings and losses pursuant to Article V.

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(b)

The Committee or the Administrator shall establish and maintain, with respect to a Participant’s Employer Matching Account, a Subaccount with respect to each Plan Year, to which shall be credited the amount equal to the Employer Matching Contributions made pursuant to Section 3.3 on behalf of such Participant in respect of such Participant’s Compensation earned during such Plan Year that he elects to defer pursuant to Section 3.1, debited by amounts equal to distributions to and withdrawals made by the Participant and/or his Beneficiary and adjusted for investment earnings and losses pursuant to Article V.

(a)	Subject to subsections (b) and (c), each Participant shall be 100% vested in his Deferral Account and his Matching Account at all times.

(b)

A Participant’s deferred Restricted Stock Units credited to a Subaccount of such Deferred Account shall be subject to the vesting conditions applicable to the Restricted Stock Unit award. The Subaccount of such Participant’s Deferral Amount for a deferred Restricted Stock Unit award shall become vested in accordance with the vesting conditions applicable to such Restricted Stock Unit award. To the extent such Restricted Stock Unit award is forfeited, the Subaccount of such Participant’s Deferral Account for such award shall be forfeited immediately following the event causing such forfeiture and the amount of such Subaccount shall be debited from such Deferral Account.

(c)

A Participant’s deferred Elective Phantom Share Amount credited to a Subaccount of such Participant’s Deferral Account shall be subject to the vesting conditions applicable to the initial or annual equity award for which such Elective Phantom Share Amount is credited. The Subaccount of such Participant’s Deferral Account for a deferred Elective Phantom Share Amount shall become vested in accordance with the vesting conditions applicable to such equity award, except as provided in subsection 7.3(b). To the extent such equity award is forfeited, the Subaccount of such Participant’s Deferral Account for such Elective Phantom Share Amount shall be forfeited immediately following the event causing such forfeiture and the amount of such Subaccount shall be debited from such Deferral Account.

(a)	Distribution at Separation from Service or Disability.

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(b)	Distribution on a Scheduled Withdrawal Date.

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(c)

Distribution upon Death. In the event a Participant dies before he has begun receiving distributions under subsection 7.1(a), his Accounts shall be paid to his Beneficiary in the same manner elected by the Participant. In the event a Participant dies after he has begun receiving distributions under subsection 7.1(a) with a remaining balance in his Accounts, the balance shall continue to be paid to his Beneficiary in the same manner.

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(a)	The election to take a Hardship Distribution shall be made by filing the form provided by the Committee or the Administrator before the date established by the Committee or the Administrator.

(b)	The Committee or the Administrator shall have made a determination that the requested distribution constitutes a Hardship Distribution in accordance with subsection 7.2(d).

(c)

The amount determined by the Committee or the Administrator as a Hardship Distribution shall be paid in a single lump sum in cash as soon as practicable after the end of the calendar month in which the Hardship Distribution election is made and approved by the Committee or the Administrator. The Hardship Distribution shall be distributed proportionately from the Subaccounts in the Participant’s Accounts, excluding the Restricted Stock Unit, Elective Phantom Share Amount or Nonelective Phantom Shares Amount Subaccounts and any amounts invested in the Sempra Energy Stock Fund.

(d)

If a Participant receives a Hardship Distribution, the Participant shall be ineligible to contribute deferrals to the Plan for the remainder of the Plan Year in which the Hardship Distribution is received or the immediately following Plan Year. “Hardship Distribution” shall mean a severe financial hardship to the Participant resulting from (i) an illness or accident of the Participant, the Participant’s spouse or of his dependent (as defined in Section 152(a) of the Code), (ii) loss of a Participant’s property due to casualty, or (iii) other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant, as determined by the Committee or the Administrator in accordance with Section 409A of the Code. The amount of the Hardship Distribution with respect to a severe financial hardship shall not exceed the amounts necessary to satisfy such hardship, plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which such hardship is or may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the Participant’s assets (to the extent the liquidation of such assets would not itself cause severe financial hardship), as determined by the Committee or the Administrator in accordance with Section 409A of the Code.

(a)

In the event there is a Change in Control, the person who is the chief executive officer (or, if not so identified, Sempra Energy’s highest ranking officer) shall name a third-party fiduciary as the sole member of the Committee immediately prior to such Change in Control and the appointed fiduciary, shall provide for the immediate distribution of the Accounts under the Plan in lump sum payments and cash to the extent permitted under Section 409A of the Code.

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(b)	Upon a Change in Control, all unvested Elective Phantom Share Amounts credited to a Director’s Account under the Plan shall vest.

(c)

Upon and after the occurrence of a Change in Control, the Company must (i) pay all reasonable administrative fees and expenses of the appointed fiduciary, (ii) indemnify the appointed fiduciary against any costs, expenses and liabilities including, without limitation, attorney’s fees and expenses arising in connection with the appointed fiduciary's duties hereunder, other than with respect to matters resulting from the gross negligence of the appointed fiduciary or its agents or employees and (iii) timely provide the appointed fiduciary with all necessary information related to the Plan, the Participants and Beneficiaries.

(d)

Notwithstanding Section 9.3, in the event there is a Change in Control no amendment may be made to this Plan except as approved by the third-party fiduciary; provided, however, that in no event shall any amendment approved by the third-party fiduciary have any retroactive effect to reduce any vested amounts allocated to a Participant’s Accounts. Upon a Change in Control, assets shall be placed in a rabbi trust in an amount which shall equal the full accrued liability under this Plan as determined by an actuarial firm appointed by the Board immediately prior to such Change in Control or, in the absence of such appointment, Willis Towers Watson or a successor actuarial firm.

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(a)	a lump sum,

(b)	annual installments (calculated as set forth at paragraph 7.1(a)(6)) over five (5) years,

(c)	annual installments (calculated as set forth at paragraph 7.1(a)(6) over ten (10) years, or

(d)	annual installments (calculated as set forth at paragraph 7.1(a)(6)) over fifteen (15) years.

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(a)	To select the Measurement Funds in accordance with Section 4.1 hereof;

(b)	To conclusively construe and interpret the terms and provisions of the Plan and to remedy any inconsistencies or ambiguities hereunder;

(c)	To select employees eligible to participate in the Plan;

(d)	To compute and certify to the amount and kind of benefits payable to Participants and their Beneficiaries;

(e)	To maintain all records that may be necessary for the administration of the Plan;

(f)	To provide for the disclosure of all information and the filing or provision of all reports and statements to Participants, Beneficiaries or governmental agencies as shall be required by law;

(g)	To make and publish such rules for the regulation and operation of the Plan and procedures for the administration of the Plan as are not inconsistent with the terms hereof;

(h)	To appoint a plan administrator or any other agent, and to delegate to them such powers and duties in connection with the administration of the Plan as the Committee may from time to time prescribe; and

(i)	To take all actions necessary for the administration of the Plan.

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(a)	The members of the Committee shall serve without compensation for their services hereunder.

(b)	The Committee is authorized at the expense of the Company to employ such legal counsel and other advisors as it may deem advisable to assist in the performance of its duties hereunder. Expenses and fees in connection with the administration of the Plan shall be paid by the Company.

(c)

To the extent permitted by applicable state law, the Company shall indemnify and save harmless the Committee and each member thereof, the Board of Directors and any delegate of the Committee who is an employee of the Company or any Affiliate and the Administrator against any and all expenses, liabilities and claims, including legal fees to defend against such liabilities and claims arising out of their discharge in good faith of responsibilities under or incident to the Plan, other than expenses and liabilities arising out of willful misconduct. This indemnity shall not preclude such further indemnities as may be available under insurance purchased by the Company or provided by the any bylaw, agreement or otherwise, of the Company as such indemnities are permitted under state law.

(a)	Claim.

(b)	Claim Decision.

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(c)	Request For Review.

(d)	Review of Decision.

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(a)

The Company shall pay all amounts payable hereunder only to the person or persons designated pursuant to the terms of the Plan and not to any other person or entity. No right, title or interest in the Plan or in any Account may be sold, pledged, assigned or transferred in any manner other than by will or the laws of descent and distribution. No right, title or interest in the Plan or in any Account shall be liable for the debts, contracts or engagements of the Participant or his successors in interest or shall be subject to disposition by transfer, alienation, anticipation, pledge, encumbrance, assignment or any other means whether such disposition be voluntary or involuntary or by operation of law by judgment, levy, attachment, garnishment or any other legal or equitable proceedings (including bankruptcy), and any attempted disposition thereof shall be null and void and of no effect, except to the extent that such disposition is permitted by the preceding sentence.

(b)	Notwithstanding the provisions of subsection 9.2(a), a Participant’s interest in his Account may be transferred by the Participant pursuant to a QDRO.

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(a)	Each Participant shall have the right to designate, revoke and redesignate Beneficiaries hereunder and to direct payment of his Distributable Amount to such Beneficiaries upon his death.

(b)	Designation, revocation and redesignation of Beneficiaries must be made in writing in accordance with the procedures established by the Committee or the Administrator and shall be effective upon delivery to the Committee or the Administrator.

(c)	If there is no Beneficiary designation in effect, or if no designated beneficiary survives the Participant, then the Participant’s spouse shall be the Beneficiary; provided, however, that if there is no surviving spouse, the duly appointed and currently acting personal representative of the Participant’s estate shall be the Beneficiary.

(d)	After the Participant’s death, any Beneficiary (other than the Participant’s estate) who is to receive installment payments may designate a secondary beneficiary to receive amounts due under this Plan to the Beneficiary in the event of the Beneficiary’s death prior to receiving full payment from the Plan. If no secondary beneficiary is designated, it shall be the Beneficiary’s estate.

(a)	As a condition of participation in this Plan, each Participant shall, if requested by the Committee, the Administrator, or the Company, undergo such examination and provide such information as may be required by the Company with respect to any insurance contracts on the Participant’s life and shall authorize the Company to purchase life insurance on his life, payable to the Company

(b)

If the Company maintains an insurance policy on a Participant’s life to fund benefits under the Plan and such insurance policy is invalidated because (i) the Participant commits suicide during the two (2) year period beginning on the first day of the first Plan Year of such Participant’s participation in the Plan or because (ii) the Participant makes any material misstatement of information or nondisclosure of medical history, then, to the extent determined by the Committee or the Administrator in its sole discretion, the only benefits that shall be payable hereunder to such Participant or his Beneficiary are the payment of the amount of deferrals of Compensation then credited to the Participant’s Accounts but without any interest including interest theretofore credited under this Plan.

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(a)	Background. Certain SET and SES employees are Participants in this Plan.

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(b)	Separation from Service

(c)	Certain Defined Terms.

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Title:	Sr. Vice President and Chief Human Resources and Administrative Officer

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

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

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

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

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

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

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

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

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

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

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

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

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

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

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

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

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

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

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

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

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

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

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

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

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

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

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

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

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

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

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

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

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

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

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

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

(i)	the Annual Report on Form 10-K of the Company filed with the Securities and Exchange Commission for the year ended December 31, 2017 (the “Annual Report”) fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

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

(i)	the Annual Report on Form 10-K of the Company filed with the Securities and Exchange Commission for the year ended December 31, 2017 (the “Annual Report”) fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

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

(i)	the Annual Report on Form 10-K of the Company filed with the Securities and Exchange Commission for the year ended December 31, 2017 (the “Annual Report”) fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

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

(i)	the Annual Report on Form 10-K of the Company filed with the Securities and Exchange Commission for the year ended December 31, 2017 (the “Annual Report”) fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

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

(i)	the Annual Report on Form 10-K of the Company filed with the Securities and Exchange Commission for the year ended December 31, 2017 (the “Annual Report”) fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

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

(i)	the Annual Report on Form 10-K of the Company filed with the Securities and Exchange Commission for the year ended December 31, 2017 (the “Annual Report”) fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

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