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actions and the timing of actions, including decisions, new regulations, and issuances of permits and other authorizations by the California Public Utilities Commission, U.S. Department of Energy, California Division of Oil, Gas, and Geothermal Resources, Federal Energy Regulatory Commission, U.S. Environmental Protection Agency, Pipeline and Hazardous Materials Safety Administration, Los Angeles County Department of Public Health, states, cities and counties, and other regulatory and governmental bodies in the United States 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; 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 regulatory assets associated with the San Onofre Nuclear Generating Station facility and 2007 wildfires) or regulatory agency approval for projects required to enhance safety and reliability;

▪	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 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 investment 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, explosions, terrorist attacks and other events that disrupt our operations, damage our facilities and systems, cause the release of greenhouse gases, 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) or may be disputed by insurers;

▪	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;

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

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

▪	changes in the tax code as a result of potential federal tax reform, such as the elimination of the deduction for interest and non-deductibility of all, or a portion of, the cost of imported materials, equipment and commodities;

▪	changes in foreign and domestic trade policies and laws, including border tariffs, revisions to favorable international trade agreements, and changes that make our exports less competitive or otherwise restrict our ability to export;

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

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

▪	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 Direct Access and Community Choice Aggregation; and

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

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▪	Sempra Energy and its consolidated entities

▪	San Diego Gas & Electric Company (SDG&E) and its consolidated variable interest entity (VIE)

▪	Southern California Gas Company (SoCalGas)

▪	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.

▪	California Utilities (which included the SDG&E and SoCalGas segments)

▪	Sempra International (which included the Sempra South American Utilities and Sempra Mexico segments)

▪	Sempra U.S. Gas & Power (which included the Sempra Renewables and Sempra Natural Gas segments)

▪	Sempra Energy – www.sempra.com

▪	SDG&E – www.sdge.com

▪	SoCalGas – www.socalgas.com

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

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

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

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

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

▪	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.

▪	electric franchises with the two counties served and the 27 cities in or adjoining its electric service territory; and

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

▪	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

▪	natural gas pipelines, ethane systems and a liquid petroleum gas pipeline and associated storage terminal

▪	electric generation facilities, including wind and solar power generation facilities and a natural gas-fired power plant in Baja California, Mexico; in February 2016, management approved a plan to market and sell the natural gas-fired power plant, as we discuss in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report

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

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

▪	1,275,600 residential

▪	151,100 commercial

▪	400 industrial

▪	5,000 direct access

▪	2,000 street and highway lighting

(1)	A QF is a generating facility which meets the requirements for QF status under the Public Utility Regulatory Policies Act of 1978.

(2)	Tolling contracts are purchased-power agreements under which SDG&E provides natural gas for generation to the energy supplier.

(3)	Agreements to purchase firm energy during specific periods at fixed prices.

•	634,700 residential

•	38,700 commercial

•	1,400 industrial

•	7,700 street and highway lighting

•	5,300 agricultural

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

(2)	In 2016, energy contracts in the Central Interconnected System, where Chilquinta Energía operates, were supplied 53

•	1,011,500 residential

•	56,600 commercial

•	4,100 industrial

•	5,100 street and highway lighting

•	500 agricultural

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

(2)	Firm capacity is estimated at 61 MW based on guidelines established by the system operator in Peru and historical water

▪	5,656,500 residential

▪	247,300 commercial

▪	26,000 industrial

▪	50 electric generation and wholesale

▪	845,600 residential

▪	28,600 commercial

▪	3,900 electric generation and transportation

▪	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.

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(1)	Ages are as of February 28, 2017.

(2)	Ms. Reed also becomes President effective on March 1, 2017.

(3)	Mr. Snell will be retired as of March 1, 2017.

(1)	Ages are as of February 28, 2017.

(2)	Mr. Avery will be retired as of April 1, 2017.

(1)	Ages are as of February 28, 2017.

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(1)	Excludes employees of variable interest entities as defined by accounting principles generally accepted in the United States of America.

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

◦	energy storage technology, and

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

▪	Sempra 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’ power sales customers’ ability to perform under long-term agreements could be impacted by changes in utility rate structures and advances in distributed and local power generation.

◦	At Sempra 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.

▪	the rates charged to our customers;

▪	our ability to site and construct new facilities;

▪	our ability to purchase or construct generating facilities;

▪	safety;

▪	the issuance of securities;

▪	accounting and income tax matters;

▪	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.

▪	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.

▪	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.

▪	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

▪	negotiation of satisfactory engineering, procurement and construction (EPC) agreements

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

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

▪	timely implementation and satisfactory completion of construction

▪	obtaining adequate and reasonably priced financing for the project

▪	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

▪	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

▪	high rates of inflation

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

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

▪	changes in government policies or personnel

▪	trade restrictions

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

▪	permitting and regulatory compliance

▪	changes in labor supply and labor relations

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

▪	expropriation of assets

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

▪	general political, social, economic and business conditions

▪	compliance with the Foreign Corrupt Practices Act and similar laws

▪	valuation of goodwill

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▪	a 566-MW electric generation facility (the Palomar generation facility) in Escondido, California

▪	a 485-MW electric generation facility (the Desert Star generation facility) in Boulder City, Nevada

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

▪	a 47-MW electric generation facility (the Cuyamaca Peak Energy Plant) in El Cajon, California

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(1)

Consists of 360,255 options to purchase shares of our common stock, all of which were granted at an exercise price of 100% of the grant date fair market value of the shares subject to the option, 1,954,322 performance-based restricted stock units and 305,736 restricted stock units that are service-based or issued in connection with certain other criteria. Each performance-based restricted stock unit represents the right to receive from zero to 1.5 shares (2.0 shares for awards granted during or after 2014) of our common stock if applicable performance conditions are satisfied. The 2,620,313 shares also includes awards granted under two previously shareholder-approved long-term incentive plans (Predecessor Plans). No new awards may be granted under these Predecessor Plans.

(2)	Represents only the weighted-average exercise price of the 360,255 outstanding options to purchase shares of common stock.

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

(1)	Sempra Energy Consolidated includes $1.8 million of audit services relating to a confidential submission of a subsidiary’s Form S-1 to the Securities and Exchange Commission for the formation of a master limited partnership and initial public offering, which have been indefinitely suspended.

(1)	Incorporated by reference from the indicated pages of the 2016 Annual Report to Shareholders, filed as Exhibit 13.1

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▪	Sempra Energy Parent recognized a cumulative-effect adjustment to retained earnings and a deferred tax asset as of January 1, 2016 of $49 million for previously unrecognized excess tax benefits from share-based compensation.

▪	Sempra Energy Parent recognized earnings consisting of excess tax benefits on the Condensed Statements of Operations of $17 million in the year ended December 31, 2016, all of which related to the three months ended March 31, 2016. Excess tax benefits of $34 million were previously recorded in Sempra Energy Parent Shareholders’ Equity in Common Stock prior to adoption of ASU 2016-09.

▪

The excess tax benefits from share-based compensation for Sempra Energy Parent were previously classified as a financing activity on Sempra Energy Parent’s Condensed Statement of Cash Flows. As now required, excess tax benefits for Sempra Energy Parent are included in Cash Flows From Operating Activities on the Condensed Statements of Cash Flows for the year ended December 31, 2016. This amendment was adopted prospectively, and therefore, we have not adjusted the Condensed Statements of Cash Flows for the prior periods presented.

▪

As a result of the provision to recognize excess tax benefits in earnings, these benefits are no longer included in the calculation of diluted earnings per share (EPS) effective January 1, 2016. The weighted-average number of common shares outstanding for diluted EPS increased by 75 thousand shares for the three months ended March 31, 2016 and 98 thousand shares and 89 thousand shares for the three months and six months ended June 30, 2016, respectively.

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

(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 9.5.

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(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 which participates in the Plan immediately prior to the Effective Date shall be deemed to participate in the Plan and to have adopted the Plan without any further action of either such 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 10, 2016.

(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

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(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 $165,000, 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.

(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.

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(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.

(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.

(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.

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(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.

(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 Compensation which a Participant may elect to defer for a Plan Year is such Compensation earned on or after the time at which the Participant elects to defer each Plan Year in accordance with subsection 3.1(a), and which is earned during such Plan Year (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).

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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.

(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

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(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:

(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

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(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:

(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.

(a)	Withholding, Generally. The Company shall have the right to withhold from any payments due under the Plan (or with respect to amounts credited to the Plan) any taxes required by law to be withheld in respect of such payment (or credit).

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(b)

Annual Deferral Amounts. For each Plan Year in which a Participant who is an employee makes a deferral under Section 3.1, the Participant’s employer shall withhold from that portion of the Participant’s Compensation that is not being deferred, in a manner determined by the employer, the Participant’s share of FICA and other employment taxes on such amount. If necessary, the Committee or the Administrator may reduce the Participant's deferrals under Section 3.1 or make deductions from his Deferral Account in order to comply with this Section 3.4, to the extent permitted under Section 409A of the Code.

(c)

Employer Matching Amounts. For each Plan Year in which a Participant is credited with a contribution to his Employer Matching Account under Section 3.3, the Participant’s employer shall withhold from the Participant’s Compensation that is not deferred, in a manner determined by the employer, the Participant’s share of FICA and other employment taxes. If necessary, the Committee or the Administrator may reduce the Participant’s Employer Matching Account in order to comply with this Section 3.4, to the extent permitted under Section 409A of the Code.

(d)

Sempra Energy Stock Fund. With respect to distributions of all or a portion of balances invested in the Sempra Energy Stock Fund, withholding obligations shall be satisfied through the surrender of the applicable withholding percentage of such distributed balances (or portion thereof) in the Sempra Energy Stock Fund.  Unless otherwise approved by the Committee, withholding obligations for Restricted Stock Units deferred into the Plan shall be satisfied by payment by the applicable Participant, deducted from other Compensation payable to such Participant which has not been deferred under the Plan, or a combination of these methods.

(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

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(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.

(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.

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(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 closing price 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 closing price 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 closing price 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.

(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.

(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.

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(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. 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.

(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.

(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).

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(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.

(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. The appointed fiduciary, shall provide for the immediate distributions of the accounts under the Plan in lump sum payments and cash to the extent permitted under Section 409A of the Code.

(b)

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.

(c)	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

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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.

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(a)

The Company shall pay all amounts payable hereunder only to the person or persons designated by the Plan and not to any other person or entity. No right, title or interest in the Plan or in any account may be sold, pledged, assigned or transferred in any manner other than by will or the laws of descent and distribution. No right, title or interest in the Plan or in any 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 (which shall include either the Participant’s probate estate or living trust) 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 description of our business

▪	An executive summary

▪	A discussion and analysis of our operating results for 2014 through 2016

▪	Information about our capital resources and liquidity

▪	Major factors expected to influence our future operating results

▪	A discussion of market risk affecting our businesses

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

▪	Sempra Energy and its consolidated entities

▪	San Diego Gas & Electric Company (SDG&E) and its consolidated variable interest entity (VIE)

▪	Southern California Gas Company (SoCalGas)

▪	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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▪	California Utilities (which included the SDG&E and SoCalGas segments)

▪	Sempra International (which included the Sempra South American Utilities and Sempra Mexico segments)

▪	Sempra U.S. Gas & Power (which included the Sempra Renewables and Sempra Natural Gas segments)

▪	Business overview

▪	Capital project updates

▪	The California Public Utilities Commission (CPUC), which regulates SDG&E’s rates and operations in California.

▪	The Federal Energy Regulatory Commission (FERC), which regulates SDG&E’s electric transmission operations and interstate transportation of natural gas and various related matters.

▪	The Nuclear Regulatory Commission (NRC), which regulates the San Onofre Nuclear Generating Station (SONGS).

▪	Municipalities and other local authorities, which may influence decisions affecting the location of utility assets, including natural gas pipelines and electric lines.

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▪	The CPUC, which regulates SoCalGas’ rates and operations in California.

▪	The California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR), which regulates the operations of SoCalGas’ natural gas storage facilities.

▪	Municipalities and other local authorities, which may influence decisions affecting the location of utility assets, including natural gas pipelines and electric lines.

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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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▪	Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company);

▪	the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE);

▪	Shell México Gas Natural (Shell);

▪	Gazprom Marketing & Trading Mexico (Gazprom);

▪	Centro Nacional de Control de Gas (CENAGAS);

▪	InterGen; and

▪	other similar counterparties.

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

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▪

Bay Gas Storage Company, Ltd. 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 91 percent of the project. It is the easternmost salt dome storage facility on the Gulf Coast, with direct service to the Florida market and markets across the Southeast, Mid-Atlantic and Northeast regions.

▪	Mississippi Hub, LLC (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.

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▪

LA Storage is a salt cavern development project in Cameron Parish, Louisiana. Sempra LNG & Midstream owns 77 percent of the project and ProLiance Transportation LLC owns the remaining 23 percent. The project’s location provides access to several LNG facilities in the area and could be positioned to support LNG export from various liquefaction terminals, when operational, if anticipated cash flows support further investment.

▪	Incremental investment. The anticipated incremental investment by Cameron LNG JV in the three-train liquefaction project is estimated to be approximately $7 billion, including the cost of the lump-sum, turnkey EPC contract, development engineering costs

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▪	Total estimated cost. The total cost of the facility, including the cost of our original facility contributed to the joint venture plus interest during construction, financing costs and required reserves, is estimated to be approximately $10 billion.

▪	Construction delay. In late October 2016, Cameron LNG JV received indication from the EPC contractor that the in-service date for each train may be delayed. Any such construction delays would defer a portion of the 2018 and 2019 earnings anticipated from this project.

▪	Transportation agreements. Sempra LNG & Midstream has agreements totaling 1.45 Bcf per day of firm natural gas transportation service to the Cameron LNG JV facilities on the Cameron Interstate Pipeline with ENGIE S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd. The terms of these agreements are concurrent with the liquefaction and regasification tolling capacity agreements.

▪

Financing agreements and guarantees. Sempra Energy and the project partners executed project financing documents and completion guarantees, which became effective on October 1, 2014 and will terminate upon financial completion of the project. Sempra Energy and the project partners executed project financing documents for senior secured debt in an initial aggregate principal amount up to $7.4 billion for the purpose of financing the cost of development and construction of the Cameron LNG JV liquefaction project. Sempra Energy has entered into guarantees under which it has severally guaranteed 50.2 percent of Cameron LNG JV’s obligations under the project financing and financing-related agreements, for a maximum amount of $3.9 billion. The project financing and completion guarantees became effective on October 1, 2014, and will terminate upon financial completion of the project, which will occur upon satisfaction of certain conditions, including all three trains achieving commercial operation and meeting certain operational performance tests. We expect the project to achieve financial completion and the completion guarantees to be terminated approximately nine months after all three trains achieve commercial operation.

▪	U.S. and South American utilities

▪	U.S. and Mexican energy infrastructure

▪	In March 2016, Sempra LNG & Midstream recorded an impairment charge related to its investment in Rockies Express ($27 million earnings impact).

▪	In May 2016, Sempra LNG & Midstream recorded a charge related to permanently released pipeline capacity with Rockies Express and others ($123 million earnings impact).

▪	In June 2016, the CPUC approved a final decision (2016 GRC FD) in the California Utilities’ 2016 GRC, effective retroactive to January 1, 2016.

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▪	In September 2016, Sempra Mexico reduced the carrying value of TdM by recognizing an impairment charge ($90 million earnings impact).

▪	In September 2016, Sempra LNG & Midstream recorded a gain on the sale of EnergySouth, the parent company of Mobile Gas and Willmut Gas ($78 million earnings impact).

▪	In September 2016, Sempra Mexico’s subsidiary, IEnova, purchased the remaining 50-percent interest in GdC for $1.144 billion, and recorded a noncash gain associated with the remeasurement of its 50-percent equity interest in GdC immediately prior to the transaction ($350 million earnings impact).

▪

In October 2016, IEnova completed a private follow-on offering of its common stock in the U.S. and outside of Mexico and a concurrent public common stock offering in Mexico, generating net proceeds of approximately $1.57 billion. Sempra Energy also purchased stock in the Mexican offering. Upon completion of the equity offerings, our beneficial ownership of IEnova decreased from 81.1 percent to 66.4 percent.

▪	In December 2016, Sempra Mexico acquired the 252-MW Ventika wind power generation facilities in Nuevo Leon, Mexico for cash of $310 million, plus the assumption of $610 million of existing debt.

▪	As of December 31, 2016, SoCalGas has recorded an estimated $780 million for certain costs and $606 million for expected recovery of costs from insurance related to the Aliso Canyon natural gas storage facility gas leak, which we discuss further in Note 15 of the Notes to Consolidated Financial Statements.

▪	Overall results of our operations

▪	Our segment results

▪	Adjusted earnings and adjusted earnings per share

▪	Significant changes in revenues, costs and earnings between periods

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(1)	After preferred dividends.

(2)	Includes after-tax interest expense ($169 million in 2016, $157 million in 2015 and $144 million in 2014), intercompany eliminations recorded in consolidation and certain corporate costs.

▪

$31 million of charges associated with prior years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD ($22 million related to 2015 estimated benefits and $9 million related to the true-up of 2012-2014 estimated benefits used in the 2016 GRC FD to actuals), as we discuss in Notes 6 and 14 of the Notes to Consolidated Financial Statements;

▪	$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 allowance for funds used during construction (AFUDC) related to equity;

▪	$7 million related to excess tax benefits associated with the adoption of a new accounting standard related to share-based compensation; and

▪	$7 million lower net interest expense.

▪	$15 million reduction to the loss from plant closure in 2015 compared to a $21 million charge in 2014 to adjust the total loss from plant closure;

▪	$26 million higher earnings from electric transmission operations primarily due to higher rate base;

▪	$14 million higher CPUC base operating margin authorized for 2015, and lower non-refundable operating costs;

▪	$7 million lower generation major maintenance costs; and

▪	$7 million higher favorable resolution of prior years’ income tax items; offset by

▪	$7 million higher earnings in 2014 associated with SDG&E’s annual FERC formulaic rate adjustment.

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▪	$49 million of charges associated with prior years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD ($43 million related to 2015 estimated benefits and $6 million related to the true-up of 2012-2014 estimated benefits used in the 2016 GRC FD to actuals);

▪	$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, as we discuss in Notes 6 and 14 of the Notes to Consolidated Financial Statements;

▪	$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.

▪	$34 million higher earnings primarily due to a lower effective tax rate, including $11 million earnings impact from higher favorable resolution of prior years’ income tax items in 2015;

▪	$31 million higher CPUC base operating margin authorized for 2015, and lower non-refundable operating costs;

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

▪	$10 million from an increase in AFUDC related to equity; and

▪	$8 million higher regulatory awards; offset by

▪	$8 million higher interest expense.

▪	$15 million higher income tax expense, including $17 million related to Peruvian tax reform, as we discuss below in “Changes in Revenues, Costs and Earnings – Income Taxes;”

▪	$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 primarily due to lower capitalized interest 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.

▪	$21 million higher earnings from operations, mainly in Peru, due to an increase in volumes and rates, which rates include foreign currency adjustments;

▪	$7 million business interruption insurance proceeds for the Santa Teresa hydroelectric power plant;

▪	$4 million higher earnings from early termination fees from commercial power contracts;

▪	$4 million decrease in earnings attributable to noncontrolling interests in 2015; and

▪	$3 million lower net interest expense, mainly in Chile, related to inflationary effect on local bonds; offset by

▪	$20 million lower earnings from foreign currency translation effects;

▪	$9 million higher income tax expense, including $18 million income tax benefit in 2014 related to Peruvian tax reform, offset by $6 million income tax expense in 2014 related to Chilean tax reform, as we discuss below in “Changes in Revenues, Costs and Earnings – Income Taxes;” and

▪	$8 million lower earnings associated with the relocation of electrical infrastructure.

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▪	$432 million noncash gain associated with the remeasurement of our 50-percent equity interest in GdC, as we discuss in Note 3 of the Notes to Consolidated Financial Statements;

▪	$20 million incremental earnings from the increase in our ownership interest in GdC from 50 percent to 100 percent on September 26, 2016; and

▪	$8 million increase in earnings from our 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, as we discuss below in “Changes in Revenues, Costs and Earnings – Earnings Attributable to Noncontrolling Interests;”

▪	$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 the TdM natural gas-fired power plant as a result of management’s decision to hold the asset for sale.

▪	$37 million higher pipeline earnings, primarily due to the start of operations of certain pipelines in the fourth quarter of 2014; and

▪	$31 million favorable variance due to effects from foreign currency and inflation, including amounts in earnings from our joint ventures; offset by

▪	$5 million losses in 2015 from operations at our TdM power plant compared to $13 million earnings for the same period in 2014, primarily due to lower capacity revenues and lower volumes;

▪	$14 million gain in 2014 from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez project;

▪	$10 million unfavorable impact from income taxes ($5 million expense in 2015 compared to $5 million benefit in 2014); and

▪	$6 million increase in earnings attributable to noncontrolling interests at IEnova.

▪	$12 million lower solar investment tax credits 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.

▪	$24 million gains in 2014 from the sale of 50-percent equity interests in Copper Mountain Solar 3 and Broken Bow 2 Wind; offset by

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

▪	$4 million higher earnings from increased solar capacity, offset by lower earnings from decreased production at wind projects.

▪	$123 million loss on permanent release of pipeline capacity, as we discuss in Note 15 of the Notes to Consolidated Financial Statements;

▪	$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 the investment in Rockies Express;

▪	$27 million impairment charge in the first quarter of 2016 related to the 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, as we discuss in Note 3 of the Notes to Consolidated Financial Statements.

▪	$29 million lower results primarily driven by the effect of lower natural gas prices;

▪	$25 million tax benefit in 2014 due to the release of Louisiana state valuation allowance against a deferred tax asset associated with Cameron LNG developments; and

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▪	$10 million development expense associated with the potential expansion of our LNG business; offset by

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

▪	$11 million higher equity earnings from Rockies Express due to additional capacity placed in service in 2015; and

▪	$9 million lower net losses from the Mesquite Power plant due to the sale of the remaining block in April 2015.

▪	$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, as we discuss below in “Changes in Revenues, Costs and Earnings – Income Taxes,” and

◦	$17 million related to excess tax benefits associated with the adoption of a new accounting standard 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 the increase in deferred compensation liability associated with the investments; offset by

▪	$10 million higher net interest expense.

▪	$39 million higher income tax benefits, including;

◦	$18 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries,

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

◦	$5 million higher income tax benefits from a decrease in state valuation allowances; offset by

▪	$11 million lower investment gains in 2015 on dedicated assets in support of our executive retirement and deferred compensation plans, net of the decrease in deferred compensation liability associated with the investments.

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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 on the impairment of TdM were calculated based on the applicable statutory tax rate, including translation from historic to current exchange rates.

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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.

▪	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 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 “Our Business” above.

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

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(1)	Rooftop solar installations, weather and energy efficiency initiatives are impacting residential and commercial volumes sold by SDG&E. As of December 31, 2016, the residential and commercial rooftop solar capacity in SDG&E’s territory totals 694 MW, an increase in capacity of 198 MW in 2016.

(2)	The decrease in electric volumes in 2016 is primarily due to the migration of regulated and non-regulated customers to tolling customers, who pay only a tolling fee and do not contribute to customer load.

(3)	In September 2016, Sempra LNG & Midstream completed the sale of EnergySouth, the parent company of Mobile Gas and Willmut Gas. Volume information for Mobile Gas and Willmut Gas has been excluded for all years presented due to immateriality.

(4)	Includes intercompany sales.

▪	$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 operation and maintenance expenses, and

◦	$5 million to adjust estimated 2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the CPUC 2016 GRC FD to actual deductions taken on the 2015 tax return. This amount reflects the increase in income tax expense, offset by

◦	$52 million of charges associated with prior years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD ($37 million related to 2015 estimated benefits and $15 million related to the true-up of 2012-2014 estimated benefits used in the 2016 GRC FD to actuals); 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.

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▪	$66 million decrease at SDG&E, including:

◦	$158 million lower cost of electric fuel and purchased power, which we discuss below, and

◦	$57 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses, offset by

◦	$88 million higher revenues from CPUC-authorized 2015 attrition and, starting in 2015, authorized revenues for the recovery of the SONGS regulatory assets pursuant to an amended settlement agreement approved by the CPUC in 2014, which we discuss below in “Depreciation and Amortization” and in Note 13 of the Notes to Consolidated Financial Statements, and

◦	$52 million higher authorized revenues from electric transmission; offset by

▪	$13 million increase at Sempra South American Utilities, including:

◦	higher rates and volumes at Luz del Sur, offset by foreign currency effects, and

◦	$9 million business interruption insurance proceeds in 2015, offset by

◦	foreign currency effects at Chilquinta Energía, offset by higher rates and volumes, and

◦	lower revenues and volumes associated with the transfer of certain non-regulated customers from Chilquinta Energía to Tecnored, an energy-services subsidiary of Sempra South American Utilities. Our energy-service companies are part of our energy-related businesses, which revenues are discussed below in “Energy-Related Businesses: Revenues and Cost of Sales.”

▪	$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 driven primarily by

◦	$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.

▪	$158 million decrease at SDG&E, including:

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

◦	a decrease in consumption due to energy efficiency initiatives, including an increase in rooftop solar installations, offset by

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

▪	$13 million increase at Sempra South American Utilities driven primarily by higher rates and volumes at both Luz del Sur and Chilquinta Energía, offset by foreign currency exchange rate effects.

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

▪	$18 million decrease at SoCalGas, which included

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◦	$83 million of charges associated with prior years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD ($72 million related to estimated 2015 benefits and $11 million related to the true-up of 2012-2014 estimated benefits used in the 2016 GRC FD to actuals),

◦	$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 operation and maintenance expenses,

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

◦	$19 million to adjust estimated 2015 income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the CPUC 2016 GRC FD to actual deductions taken on the 2015 tax return. This amount reflects the increase in income tax expense; and

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

◦	$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 operation and maintenance expenses, and

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

▪	$366 million decrease at SoCalGas, which included

◦	$528 million decrease in cost of natural gas sold, due to $543 million from lower average prices offset by $15 million from higher sales volumes driven mainly by cooler weather in 2015, offset by

◦	$57 million higher revenues from CPUC-authorized 2015 attrition,

◦	$45 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses,

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

◦	$13 million higher regulatory awards;

▪	$44 million decrease at SDG&E, which included

◦	$55 million decrease in cost of natural gas sold, primarily due to $52 million from lower average prices, offset by

◦	$8 million higher revenues from CPUC-authorized 2015 attrition; and

▪	$28 million lower revenues at Sempra Mexico primarily due to foreign currency effects and lower natural gas prices at Ecogas.

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(1)	Includes eliminations of intercompany activity.

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

▪	$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 GdC 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.

▪	$316 million decrease at Sempra LNG & Midstream mainly from lower natural gas prices and volumes and lower power revenues due to the sale of the remaining block of Mesquite Power and a related power sale contract in April 2015, as well as from the deconsolidation of Cameron LNG, LLC as of October 1, 2014;

▪	$121 million lower revenues at Sempra Mexico primarily due to lower natural gas prices and volumes in its gas business and lower power prices and volumes and capacity revenues in its power business, offset by higher transportation revenues from a section of the Sonora natural gas pipeline that commenced operations in the fourth quarter of 2014; and

▪	$3 million decrease at Sempra South American Utilities primarily due to foreign currency effects, offset by higher revenues associated with the transfer of certain non-regulated customers from Chilquinta Energía. Those revenues were included in “Electric Revenues” in prior years; offset by

▪	$139 million primarily from lower intercompany eliminations associated with sales between Sempra LNG & Midstream and Sempra Mexico.

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▪	$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.

▪	$242 million decrease at Sempra LNG & Midstream primarily due to lower natural gas costs and volumes and lower electric fuel costs due to the sale of the remaining block of Mesquite Power in April 2015; and

▪	$129 million decrease at Sempra Mexico primarily due to lower natural gas costs and volumes; offset by

▪	$143 million primarily from lower intercompany eliminations of costs associated with sales between Sempra LNG & Midstream and Sempra Mexico.

(1)	Includes intercompany eliminations recorded in consolidation.

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

◦	$40 million higher expenses associated with CPUC-authorized refundable programs, for which all costs incurred are fully recovered in revenue (refundable program expenses), and

◦	$10 million at Otay Mesa VIE primarily due to major maintenance at the Otay Mesa Energy Center (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, for which all costs incurred are fully recovered in revenue (refundable program expenses), 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 GdC in September 2016; offset by

▪	$21 million decrease at Sempra LNG & Midstream, $9 million of which is attributable to the sale of EnergySouth in September 2016.

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▪	$59 million decrease at SDG&E, which included

◦	$53 million lower expenses associated with CPUC-authorized refundable programs, for which all costs incurred are fully recovered in revenue (refundable program expenses), and

◦	$8 million lower non-refundable operating costs, including $11 million lower major maintenance costs at its electric generating facilities, as well as labor, contract services and administrative and support costs; and

▪	$18 million decrease at Parent and Other primarily due to lower employee benefit and deferred compensation costs; offset by

▪	$40 million increase at SoCalGas primarily due to $45 million higher expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses).

▪	$1,312 million in 2016

▪	$1,250 million in 2015

▪	$1,156 million in 2014

▪	$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 higher depreciation at SoCalGas from higher utility plant base.

▪

$74 million higher depreciation and amortization at SDG&E mainly from $42 million from the start of amortization of SONGS regulatory assets and from higher utility plant base. As we discuss in Note 13 of the Notes to Consolidated Financial Statements, based on an amended settlement agreement approved by the CPUC in 2014, SDG&E is authorized to recover in rates its remaining investment in SONGS, including base plant and construction work in progress; and

▪	$30 million higher depreciation at SoCalGas from higher utility plant base; offset by

▪	$12 million lower depreciation expense at Sempra LNG & Midstream primarily due to the deconsolidation of Cameron LNG, LLC as of October 1, 2014.

▪	$27 million for Copper Mountain Solar 3

▪	$19 million for the first phase of the Energía Sierra Juárez Wind project

▪	$14 million for the Broken Bow 2 Wind project

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▪	$6 million in 2016

▪	$104 million in 2015

▪	$81 million in 2014

▪	$19 million higher equity earnings from Rockies Express mainly due to east-to-west capacity placed in service in 2015; and

▪	$4 million higher earnings at Sempra Renewables due to higher earnings from increased solar capacity, offset by lower earnings from decreased production at wind projects.

▪	$132 million in 2016

▪	$126 million in 2015

▪	$137 million in 2014

▪	$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.

▪	$24 million lower investment gains in 2015 on dedicated assets in support of our executive retirement and deferred compensation plans; and

▪	$14 million lower electrical infrastructure income in Peru; offset by

▪	$11 million lower net losses on interest rate and foreign exchange instruments in 2015;

▪	$9 million higher income from the sale of other investments;

▪	$8 million lower foreign currency losses in 2015; and

▪	$1 million increase in equity-related AFUDC, including

◦	$10 million increase at SoCalGas, offset by

◦	$10 million decrease at Sempra Mexico related to construction of the Sonora natural gas pipeline.

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▪	$553 million in 2016

▪	$561 million in 2015

▪	$554 million in 2014

▪	$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.

▪	$24 million increase in long-term debt interest at Parent and Other primarily due to debt issuances in 2014 and 2015, net of maturities; and

▪	$15 million increase at SoCalGas primarily due to debt issuances in 2014 and 2015; offset by

▪	$33 million increase in capitalized interest at Sempra LNG & Midstream primarily related to its investment in Cameron LNG JV, which has not commenced its planned principal operations.

▪

$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 includes $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

▪	$34 million income tax benefit associated with the adoption of a new accounting standard 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, as discussed below and in Note 6 of the Notes to Consolidated Financial Statements.

▪	$21 million higher favorable resolution of prior years’ income tax items including settlement with the California Franchise Tax Board in 2015;

▪	$20 million U.S income tax expense in 2015 on the planned repatriation from certain non-U.S. subsidiaries, compared to $38 million in 2014, as discussed below; and

▪	$17 million charge in 2014 to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS, as we discuss in Note 13 of the Notes to Consolidated Financial Statements; offset by

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▪	$25 million tax benefit in 2014 due to the release of Louisiana state valuation allowance against a deferred tax asset associated with Cameron LNG developments.

▪	$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 associated with the adoption of a new accounting standard 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 includes $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 associated with the adoption of a new accounting standard related to share-based compensation.

▪	$10 million higher favorable resolution of prior years’ income tax items in 2015;

▪	higher deductions for certain repairs expenditures that are capitalized for financial statement purposes; and

▪	higher deductions for self-developed software expenditures.

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▪	$78 million in 2016

▪	$85 million in 2015

▪	$38 million in 2014

▪	start of operations in December 2014 of the Los Ramones I pipeline;

▪	higher earnings from the Energía Sierra Juárez wind-powered electric generation facility commencing operations in the second quarter of 2015; and

▪	equity-related AFUDC for the Los Ramones Norte pipeline project.

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

◦	$82 million gain associated with the remeasurement of our 50-percent equity interest in GdC, 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 due to an increase in operating expenses as a result of major maintenance at the OMEC plant in the second quarter of 2016.

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▪	$7 million decrease in earnings attributable to noncontrolling interests at Sempra South American Utilities, before adjustments for the effects of foreign currency translation; offset by

▪	$6 million increase in earnings attributable to noncontrolling interests of IEnova in 2015.

▪	$51.77 in 2016

▪	$47.56 in 2015

▪	$45.98 in 2014

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▪	$3 billion issuances of debt with maturities greater than 90 days, including $498 million at SDG&E and $499 million at SoCalGas

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

▪	$692 million net increase in short-term debt

▪	$761 million net proceeds from Sempra LNG & Midstream’s sale of EnergySouth and its 25-percent interest in Rockies Express

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

▪	$100 million withdrawals from the Nuclear Decommissioning Trust assets at SDG&E for SONGS decommissioning costs. We discuss the Nuclear Decommissioning Trusts further in Note 13 of the Notes to Consolidated Financial Statements

▪	$4.2 billion in expenditures for property, plant and equipment (PP&E), including $1.4 billion at SDG&E and $1.3 billion at SoCalGas

▪	$2.1 billion retirements and repayments of debt with maturities greater than 90 days, including $204 million at SDG&E and $3 million at SoCalGas

▪	$1.6 billion for investments in and acquisitions of businesses

▪	$686 million common dividends paid

(1)	Amounts at Sempra Energy Consolidated include $228 million held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated, as we discuss below.

(2)	Available unused credit is the total available on the Sempra Energy, Sempra Global and the California Utilities’ credit facilities. Borrowings on

▪	finance capital expenditures

▪	meet liquidity requirements

▪	fund shareholder dividends

▪	fund new business acquisitions or start-ups

▪	repay maturing long-term debt

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

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

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▪	$451 million net decrease related to the natural gas leak at the Aliso Canyon storage facility, comprised of:

◦	$221 million net decrease in reserve for accrued expenditures 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, offset by

◦

$281 million net increase in receivable for expected insurance recovery in 2016 compared to a $325 million increase in 2015. The $281 million net increase includes $450 million of additional accruals, offset by $169 million in insurance proceeds. We discuss the Aliso Canyon leak further in Note 15 of the Notes to Consolidated Financial Statements and in “Risk Factors” in our 2016 Annual Report on Form 10-K;

▪	$267 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, as we discuss in “Results of Operations” above;

▪

$348 million net decrease in undercollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2016 at the California Utilities compared to a $544 million net decrease in 2015. Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time. See further discussion of changes in regulatory balances at both SDG&E and SoCalGas below;

▪	$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 current moratorium on natural gas injections at the Aliso Canyon storage facility;

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

▪	$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;

▪	$36 million net decrease in greenhouse gas 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.

▪	$544 million net decrease in net undercollected regulatory balancing accounts in 2015 at the California Utilities (including long-term amounts included in regulatory assets) compared to a $277 million net increase in 2014;

▪	$245 million higher net income, adjusted for noncash items included in earnings, in 2015 compared to 2014, primarily due to improved operations at the California Utilities, as well as higher pipeline earnings at Sempra Mexico;

▪	$65 million decrease in inventories in 2015 compared to a $133 million increase in 2014, primarily due to mandated natural gas withdrawals, as well as lower volume added to storage at SoCalGas in 2015 as a result of the moratorium on natural gas injections at its Aliso Canyon natural gas storage facility; and

▪	$126 million decrease in settlement payments and associated legal fees for wildfire claims at SDG&E in 2015 compared to 2014; offset by

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▪	$157 million decrease in accounts payable in 2015 compared to a $109 million increase in 2014, primarily due to lower average cost of natural gas purchased at SoCalGas, as well as the moratorium on natural gas injections at its Aliso Canyon storage facility;

▪	$179 million in purchases of greenhouse gas allowances ($117 million at SDG&E and $62 million at SoCalGas);

▪	$99 million increase in accounts receivable in 2015 compared to a $44 million decrease in 2014. The 2015 increase was primarily due to an increase in physical gas sales at SoCalGas; and

▪	$325 million receivable for expected insurance recovery of certain expenditures related to the natural gas leak at the Aliso Canyon storage facility, and $274 million reserve for accrued expenditures expected to be paid in 2016 related to the leak.

▪	$55 million decrease in net undercollected regulatory balancing accounts (including long-term amounts included in regulatory assets) 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 greenhouse gas 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.

▪	$474 million decrease in net undercollected regulatory balancing accounts in 2015 compared to a $47 million increase in 2014 (including long-term amounts included in regulatory assets in 2014). The 2015 decrease was primarily associated with the electric commodity accounts;

▪	$126 million decrease in settlement payments and associated legal fees for wildfire claims in 2015 compared to 2014; and

▪	$102 million higher net income, adjusted for noncash items included in earnings, in 2015 compared to 2014, primarily due to improved operations; offset by

▪	$117 million in purchases of greenhouse gas allowances in 2015; and

▪	$88 million income tax payments, net of income tax refunds, in 2015 due to utilization of net operating losses carried forward in 2015.

▪	$451 million net decrease related to the natural gas leak at the Aliso Canyon storage facility, comprised of:

◦	$221 million net decrease in reserve for accrued expenditures 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, offset by

◦	$281 million net increase in receivable for expected insurance recovery in 2016 compared to a $325 million increase in 2015. The $281 million net increase includes $450 million of additional accruals, offset by $169 million in insurance proceeds;

▪	$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 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 greenhouse gas 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 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 included in regulatory assets) 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; and

▪	$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.

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▪	$70 million decrease in net undercollected regulatory balancing accounts in 2015 (including long-term amounts included in regulatory assets) compared to a $230 million decrease in net overcollected regulatory balancing accounts in 2014, primarily due to changes associated with the fixed cost balancing accounts;

▪	$102 million decrease in inventories in 2015 compared to a $113 million increase in 2014, primarily due to mandated natural gas withdrawals, as well as lower volume added to storage in 2015 as a result of the moratorium on natural gas injections at the Aliso Canyon natural gas storage facility; and

▪	$110 million higher net income, adjusted for noncash items included in earnings, in 2015 compared to 2014, primarily due to improved operations; offset by

▪	$143 million decrease in accounts payable in 2015 compared to a $156 million increase in 2014, primarily due to lower average cost of natural gas purchased, as well as the moratorium on natural gas injections at its Aliso Canyon facility;

▪	$90 million increase in accounts receivable in 2015 compared to a $30 million decrease in 2014. The increase in 2015 was primarily due to an increase in physical gas sales in 2015;

▪	$62 million in purchases of greenhouse gas allowances in 2015; and

▪	$325 million receivable for expected insurance recovery of certain expenditures related to the natural gas leak at the Aliso Canyon storage facility, and $274 million reserve for accrued expenditures expected to be paid in 2016 related to the leak.

▪	$1.4 billion increase in expenditures for investments and acquisition of businesses. See further detail of these expenditures below;

▪	$1.1 billion increase in capital expenditures. See further detail of capital expenditures below;

▪	in 2015, $347 million of net proceeds received 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 25-percent interest in Rockies Express in May 2016;

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

▪	$100 million decrease in Nuclear Decommissioning Trust assets in 2016 primarily as a result of CPUC authorization to withdraw trust funds for SONGS decommissioning costs incurred in 2015 and 2016, compared to a $60 million decrease in 2015.

▪	$347 million of net proceeds received from Sempra LNG & Midstream’s sale of the remaining block of its Mesquite Power plant;

▪	$43 million net decrease in advances to unconsolidated affiliates in 2015 compared to $167 million net increase in advances in 2014;

▪	$60 million decrease in Nuclear Decommissioning Trust assets at SDG&E in 2015 due to withdrawals for SONGS decommissioning costs incurred in 2013 and 2014. We discuss the Nuclear Decommissioning Trusts further in Note 13 of the Notes to Consolidated Financial Statements; and

▪	$26 million proceeds received from Sempra Renewables’ sale of the Rosamond Solar development project; offset by

▪	in 2014, $148 million cash proceeds, net of cash sold, from Sempra Renewables’ sale of 50-percent equity interests in Copper Mountain Solar 3 ($66 million) and Broken Bow 2 Wind ($58 million), and Sempra Mexico’s sale of a 50-percent equity interest in Energía Sierra Juárez ($24 million); and

▪	$33 million higher capital expenditures in 2015.

▪	$266 million increase in capital expenditures; and

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

▪	$100 million decrease in Nuclear Decommissioning Trust assets in 2016 primarily as a result of CPUC authorization to withdraw trust funds for SONGS decommissioning costs incurred in 2015 and 2016, compared to a $60 million decrease in 2015.

▪	$60 million decrease in Nuclear Decommissioning Trust assets in 2015 as a result of CPUC authorization to access trust funds for SONGS decommissioning costs incurred in 2013 and 2014; and

▪	$30 million expenditures related to a long-term service agreement in 2014; offset by

▪	$33 million increase in capital expenditures.

▪	$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.

▪	$248 million increase in capital expenditures; and

▪	$50 million increase in net advances to Sempra Energy in 2015.

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(1)	Net of cash and cash equivalents acquired.

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

(3)	Includes capitalized interest of $47 million, $49 million and $12 million in 2016, 2015 and 2014, respectively, on Sempra LNG & Midstream’s investment, as the joint venture has not commenced planned principal operations.

(4)	Investment in industrial development bonds.

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

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▪	$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, as we discuss in Note 1 of the Notes to Consolidated Financial Statements; 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 on debt, including higher payments of long-term debt of $255 million (payments of $991 million in 2016 compared to $736 million in 2015), offset by lower payments of commercial paper and other short-term debt with maturities greater than 90 days of $52 million (payments of $1.07 billion in 2016 compared to $1.12 billion in 2015);

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

▪	$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, discussed in Note 2 of the Notes to Consolidated Financial Statements, $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, including a decrease in issuances of long-term debt of $812 million ($1.6 billion in 2016 compared to $2.4 billion in 2015), offset by an increase in commercial paper and other short-term debt borrowings with maturities greater than 90 days of $771 million ($1.4 billion in 2016 compared to $633 million in 2015).

▪	$622 million net decrease in short-term debt in 2015 compared to a $412 million net increase in 2014; and

▪	$280 million lower issuances of debt, including a decrease in commercial paper and other short-term debt borrowings with maturities greater than 90 days of $630 million ($633 million in 2015 compared to $1.3 billion in 2014), offset by higher issuances of long-term debt of $350 million ($2.4 billion in 2015 compared to $2 billion in 2014); offset by

▪	$180 million lower payments on debt, including lower payments of long-term debt of $467 million ($736 million in 2015 compared to $1.2 billion in 2014), offset by higher payments of commercial paper and other short-term debt with maturities greater than 90 days of $287 million ($1.1 billion in 2015 compared to $831 million in 2014);

▪	$74 million purchase of noncontrolling interests in 2014; and

▪	$52 million tax benefit related to share-based compensation in 2015 (see additional discussion in Notes 2 and 6 of the Notes to Consolidated Financial Statements).

▪	$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.

▪	$523 million higher payments on long-term debt in 2015;

▪	$131 million net decrease in short-term debt in 2015 compared to a $187 million net increase in 2014; and

▪	$100 million increase in common stock dividends paid ($300 million in 2015 compared to $200 million in 2014); offset by

▪	$344 million higher issuances of debt with maturities greater than 90 days in 2015.

▪	$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.

▪	$250 million payments of long-term debt in 2014; and

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

▪	$148 million lower issuances of long-term debt in 2015; and

▪	$50 million net decrease in short-term debt in 2015 compared to an $8 million net increase in 2014.

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

▪	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 fund future expenditures for the expansion and improvement of their utility plants.

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▪	$51 million in 2016

▪	$52 million in 2015

▪	$56 million in 2014

▪	$686 million in 2016

▪	$628 million in 2015

▪	$598 million in 2014

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(1)	Includes noncontrolling interest and debt of Otay Mesa VIE with no significant impact.

▪	Sempra Energy Consolidated: comprehensive income exceeding dividends plus the sale of noncontrolling interests, partially offset by an increase in both long-term and short-term debt

▪	SDG&E: comprehensive income exceeding dividends, partially offset by a net increase in debt

▪	SoCalGas: primarily an increase in both long-term and short-term debt, partially offset by comprehensive income

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(1)	We calculate expected interest payments using the stated interest rate for fixed-rate obligations. We calculate expected interest payments for variable-rate obligations, including fixed-to-floating interest rate swaps, based on forward rates in effect at December 31, 2016.

(2)	Of the present value of the net minimum lease payments, $500 million will be recorded as a capital lease obligation when construction of the peaker plant facility is completed and delivery of contracted power commences, which is scheduled to occur in June 2017.

(3)

Sempra LNG & Midstream has a purchase agreement with a major international company for the supply of LNG to the Energía Costa Azul terminal. The agreement is priced using a predetermined formula based on forward prices of the index applicable from 2017 to 2028 and an estimated one percent escalation in 2029. We provide more information about this contract in Note 15 of the Notes to Consolidated Financial Statements.

(4)	Amounts represent expected company contributions to the plans for the next 10 years.

(5)	Excludes amounts related to the natural gas leak at SoCalGas’ Aliso Canyon natural gas storage facility.

(1)	SDG&E calculates expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps. SDG&E calculates expected interest payments for variable-rate obligations based on forward rates in effect at December 31, 2016.

(2)	Of the present value of the net minimum lease payments, $500 million will be recorded as a capital lease obligation when construction of the peaker plant facility is completed and delivery of contracted power commences, which is scheduled to occur in June 2017.

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

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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

▪	$58 million for Sempra Energy Consolidated

▪	$22 million for SDG&E

▪	$29 million for SoCalGas

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▪

In January 2016, the Governor of the State of California issued the Governor’s Order proclaiming a state of emergency to exist in Los Angeles County due to the natural gas leak at the Aliso Canyon facility. The Governor’s Order 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 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, SoCalGas entered into a Stipulated Order for Abatement with the SCAQMD and agreed to take various actions in connection with injecting and withdrawing natural gas at Aliso Canyon, sealing the well, monitoring, reporting, safety and funding a health impact study, among other things. In February 2017, SoCalGas entered into a settlement agreement with the SCAQMD that

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▪	In January 2016, the DOGGR and CPUC selected Blade Energy Partners (Blade) to conduct an independent analysis under the direction and supervision of the DOGGR and CPUC to be funded by SoCalGas to investigate the technical root cause of the Aliso Canyon natural gas leak. The timing of the root cause analysis is under the control of Blade, the DOGGR and the CPUC.

▪

In June 2016, the California Division of Occupational Safety and Health issued four citations to SoCalGas alleging violations of various regulations, including that SoCalGas failed to ensure that testing and inspection of well casing and tubing at the Aliso Canyon storage facility complied with testing and inspection requirements, with total penalties of $60,800. SoCalGas has filed an appeal of all four citations on the grounds that no violations of the cited regulations occurred, the citations are all preempted by federal law, the citations were not issued in a timely manner, and two of the citations are duplicative.

▪	In February 2017, the CPUC opened a proceeding 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 “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 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 Secretary of Energy to establish an Interagency Task Force comprised of representatives from various federal agencies and representatives of state and local governments.

▪

the continued prohibition against SoCalGas injecting any natural gas into the Aliso Canyon facility until a comprehensive review of the safety of the gas storage wells at the facility is completed in accordance with regulations adopted by DOGGR, the State Oil and Gas Supervisor has made a safety determination and other required findings, at least one public hearing has been held in the affected community, and the Executive Director of the CPUC has issued a concurring letter regarding the Supervisor’s determination of safety;

▪	that all gas storage wells returning to service at the Aliso Canyon storage field inject or produce gas only through the interior metal tubing and not through the annulus between the tubing and the well casing, which allows SoCalGas wells to operate with two complete barriers to mitigate the potential for an uncontrolled release of natural gas; and

▪	a CPUC proceeding (which was opened in February 2017) 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, and to consult with various

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▪	CARB, in consultation with any local air district and DOGGR, to develop a natural gas storage facility continuous air monitoring program;

▪	DOGGR, in consultation with CARB, to determine by regulation what constitutes a reportable leak from a gas storage well and the timeframe for reporting those leaks;

▪	DOGGR to perform random onsite inspections of some gas storage wells annually and post the results on its website; and

▪	the operator of each natural gas storage well to develop and maintain a risk management plan, a comprehensive well training and mentoring program for employees whose job duties involve the safety of operations and maintenance of gas storage wells and associated equipment, and a leak prevention and response plan.

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▪	50 percent of the revenue requirements associated with completed PSEP Phase 1 projects;

▪	authorized tracking of Phase 2 costs;

▪	file two reasonableness review applications for Phase 1 projects completed through 2017;

▪	file a Phase 2 revenue requirement forecast application for costs to be incurred in 2017 and 2018; and

▪	include all other PSEP costs not subject to prior applications in their 2019 GRC applications and any future GRCs.

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▪	DOE FTA approval received in July 2015

▪	Non-FTA approval received in July 2016

▪	FERC permit received in May 2016

▪	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 February 2016, 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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▪	lowering the federal income tax rate,

▪	eliminating the deduction for interest expense,

▪	treating all capital expenditures as a current deduction,

▪	implementing a territorial tax system, allowing for future foreign earnings to be repatriated with reduced or no federal income tax expense, and

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▪	adding a border adjustment tax where profits from exports are tax-exempt, while imports are taxed.

▪	requiring standardized OTC derivatives to be traded on registered exchanges regulated by the U.S. Commodity Futures Trading Commission (CFTC)

▪	imposing new and potentially higher capital and margin requirements and

▪	authorizing the establishment of commodity position limits, the latter of which is pending final approval.

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(1)	Before the effects of 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, 2016 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, 2016 recorded to OCI at the end of each reporting period, primarily at our South American businesses.

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▪	actions and the timing of actions, including decisions, new regulations, and issuances of permits and other authorizations by the California Public Utilities Commission, U.S. Department of Energy, California Division of Oil, Gas, and Geothermal Resources, Federal Energy Regulatory Commission, U.S. Environmental Protection Agency, Pipeline and Hazardous Materials Safety

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▪	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; 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 regulatory assets associated with the San Onofre Nuclear Generating Station facility and 2007 wildfires) or regulatory agency approval for projects required to enhance safety and reliability;

▪	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 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 investment 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, explosions, terrorist attacks and other events that disrupt our operations, damage our facilities and systems, cause the release of greenhouse gases, 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) or may be disputed by insurers;

▪	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;

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

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

▪	changes in the tax code as a result of potential federal tax reform, such as the elimination of the deduction for interest and non-deductibility of all, or a portion of, the cost of imported materials, equipment and commodities;

▪	changes in foreign and domestic trade policies and laws, including border tariffs, revisions to favorable international trade agreements, and changes that make our exports less competitive or otherwise restrict our ability to export;

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

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

▪	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 Direct Access and Community Choice Aggregation; and

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

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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.

(3)	SDG&E redeemed all series of its outstanding shares of contingently redeemable stock in 2013.

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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.

(3)	SDG&E redeemed all series of its outstanding shares of contingently redeemable stock in 2013.

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▪	Sempra Utilities, which includes our San Diego Gas & Electric Company (SDG&E), Southern California Gas Company (SoCalGas) and Sempra South American Utilities reportable segments; and

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

▪	California Utilities (which included the SDG&E and SoCalGas segments)

▪	Sempra International (which included the Sempra South American Utilities and Sempra Mexico segments)

▪	Sempra U.S. Gas & Power (which included the Sempra Renewables and Sempra Natural Gas segments)

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▪	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;

▪	proposed regulatory decisions;

▪	final regulatory orders;

▪	a commission-authorized mechanism established for the accumulation of costs;

▪	status of applications for rehearings or state court appeals;

▪	specific approval from a commission; and

▪	historical experience.

▪	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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(1)	At December 31, 2016 and 2015, SoCalGas’ natural gas inventory for core customers is net of an inventory loss related to the Aliso Canyon natural gas leak, which we discuss in Note 15.

▪	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.

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▪	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, 2016, includes $388 million in electric transmission assets and $46 million in construction work in progress related to SDG&E’s 91-percent interest in the Southwest Powerlink (SWPL) transmission line, jointly owned by SDG&E with other utilities. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for its share of the project and participates in decisions concerning operations and capital expenditures.

(2)	Includes capital lease assets of $258 million at both December 31, 2016 and 2015, primarily related to variable interest entities of which SDG&E is not the primary beneficiary.

(3)	Includes capital lease assets of $21 million and $20 million at December 31, 2016 and 2015, respectively.

(4)	Includes capital lease assets of $32 million and $30 million at December 31, 2016 and 2015, respectively.

(5)	Includes $128 million and $142 million at December 31, 2016 and 2015, respectively, of utility plant, primarily pipelines and other distribution assets, at Ecogas. Includes $204 million and $28 million at December 31, 2015 of utility plant, primarily pipelines and other distribution assets, at Mobile Gas and Willmut Gas, respectively.

(6)	Includes capital lease assets of $136 million at both December 31, 2016 and 2015, related to a build-to-suit lease.

(7)	Estimated useful lives are for land rights.

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(1)	Includes accumulated depreciation for assets under capital lease of $39 million and $34 million at December 31, 2016 and 2015, respectively. Includes $229 million at December 31, 2016 related to SDG&E’s 91-percent interest in the SWPL transmission line, jointly owned by SDG&E and other utilities.

(2)	Includes accumulated depreciation for assets under capital lease of $31 million and $29 million at December 31, 2016 and 2015, respectively.

(3)	Includes $33 million and $36 million at December 31, 2016 and 2015, respectively, of accumulated depreciation for utility plant at Ecogas. Includes $35 million and $3 million at December 31, 2015 of accumulated depreciation for utility plant at Mobile Gas and Willmut Gas, respectively.

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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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▪	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 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

▪	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, 2016)

▪	natural gas distribution and transportation systems

▪	LNG terminal

▪	wind farm

▪	certain power generation plants (solar and wind)

▪	natural gas distribution systems (sold in September 2016)

▪	natural gas transportation systems

▪	underground natural gas storage facilities

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(1)	The current portions of the obligations 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 on the Sempra Energy Consolidated Balance Sheet at December 31, 2016, as we discuss in Note 3.

(3)	The revisions are primarily related to revised estimates of cash flows and, additionally in 2016, to changes in the cost of removal rates primarily for natural gas assets based on updated cost studies approved in the final decision in the 2016 General Rate Case. We discuss the 2016 General Rate Case in Note 14.

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

▪

Decoupled revenue – The regulatory framework permits the California Utilities to recover authorized revenue based on estimated annual demand forecasts approved in regular proceedings before the CPUC. Any difference between actual demand and the annual demand approved in the proceedings is recovered or refunded in authorized revenue in the subsequent year. This design, commonly known as “decoupling,” is intended to minimize any impact on earnings due to variability in volumetric demand for electricity and natural gas.

▪

Commodity costs – The regulatory framework authorizes the California Utilities to recover the actual cost of natural gas procured and delivered to its core customers in rates substantially as incurred. Actual electricity procurement costs are recovered as power is delivered, or to the extent actual amounts vary from forecasts, generally recovered or refunded within the subsequent year. The California Utilities 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 California Independent System Operator (ISO) 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 California ISO settles SDG&E costs and revenues on an hourly and real-time net basis.

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(1)	Excludes intercompany revenues.

▪	pipeline transportation and storage of natural gas, liquid petroleum gas and ethane as capacity is provided;

▪	sale of natural gas as deliveries are made;

▪	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

▪

a natural gas-fired power plant that generates revenues from selling electricity and/or capacity to the California ISO and to governmental, public utility and wholesale power marketing entities as the power is delivered at the interconnection point. In February 2016, management approved a plan to market and sell Termoeléctrica de Mexicali (TdM). As a result, we classified it as held for sale. We discuss TdM further in Note 3.

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▪	pipeline capacity costs, and 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 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 S.A. and Eletrans II S.A. (collectively, Eletrans), which is a joint venture of Chilquinta Energía.

(3)	U.S. dollar-denominated loan, at a variable interest rate based on the 30-day LIBOR plus 450 basis points (5.27 percent at December 31, 2016), to finance the Los Ramones Norte pipeline project.

(4)	U.S. dollar-denominated loan, at a variable interest rate based on the 30-day LIBOR plus 637.5 basis points (7.15 percent at December 31, 2016), to finance the first phase of the Energía Sierra Juárez wind project, which is a joint venture of IEnova.

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

(6)	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.

(7)	At December 31, 2015, net receivable included outstanding advances to Sempra Energy of $50 million at an interest rate of 0.11%.

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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, 2016 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 $152 million at Sempra Energy’s consolidated Mexican subsidiaries at December 31, 2016.

▪	Wholly owned GdC has a long-term debt agreement (see Note 5) that requires it to maintain a reserve account to pay the projects’ debt. Under this restriction, net assets totaling $14 million are restricted at December 31, 2016.

▪

Wholly owned Ventika has long-term debt agreements (see Note 5) 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 $38 million are restricted at December 31, 2016.

▪

Energía Sierra Juárez, a 50-percent owned and unconsolidated joint venture of Sempra Mexico (see Notes 3 and 4), 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 draws, 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 $10 million are restricted as of December 31, 2016.

▪

Ductos y Energéticos del Norte, S. de R.L. de C.V. (DEN), a 50-percent owned and unconsolidated joint venture of Sempra Mexico (see Notes 3 and 4), has a 50-percent owned and unconsolidated joint venture with a long-term debt agreement that requires it to maintain a reserve account to pay projects’ debt. Under these restrictions, net assets totaling $130 million are restricted at December 31, 2016.

▪

Wholly owned solar project 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 indebtedness, make acquisitions and undertake certain actions, while also requiring maintenance of certain debt ratios. Under these restrictions, net assets totaling $9 million are restricted at December 31, 2016.

▪	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, 2016,

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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 operation and maintenance requirements. We discuss Sempra Energy guarantees associated with these requirements in Note 4. At December 31, 2016, as a result of these requirements, there were total restricted net assets at these joint ventures of approximately $265 million.

▪	91-percent owned Bay Gas has long-term debt instruments containing restrictions relating to the payment of dividends and other distributions if Bay Gas does not maintain a specified debt service coverage ratio. Bay Gas had no restricted net assets at December 31, 2016.

▪

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 $5.5 billion are restricted at December 31, 2016.

(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)	Income at Luz del Sur associated with the relocation of electrical infrastructure.

(3)	Interest on regulatory balancing accounts.

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▪	Sempra Energy, SDG&E and SoCalGas recognized a cumulative-effect adjustment to retained earnings and a deferred tax asset as of January 1, 2016 of $107 million, $23 million and $15 million, respectively, for previously unrecognized excess tax benefits from share-based compensation.

▪

Sempra Energy, SDG&E and SoCalGas recognized earnings consisting of excess tax benefits on the Consolidated Statements of Operations of $34 million, $7 million and $4 million, respectively, in the year ended December 31, 2016, all of which related to the three months ended March 31, 2016. The $34 million was previously recorded in Sempra Energy Shareholders’ Equity in Common Stock prior to adoption of ASU 2016-09.

▪

The excess tax benefits from share-based compensation for Sempra Energy were previously classified as a financing activity on Sempra Energy’s Consolidated Statement of Cash Flows. As now required, the excess tax benefits for Sempra Energy, SDG&E and SoCalGas are included in Cash Flows From Operating Activities on the Consolidated Statements of Cash Flows for the year ended December 31, 2016. This amendment was adopted prospectively, and therefore, we have not adjusted the Consolidated Statements of Cash Flows for the prior periods presented.

▪

As a result of the provision to recognize excess tax benefits in earnings, these benefits are no longer included in the calculation of diluted earnings per share (EPS) effective January 1, 2016. The weighted-average number of common shares outstanding for diluted EPS increased by 75 thousand shares for the three months ended March 31, 2016 and 98 thousand shares and 89 thousand shares for the three months and six months ended June 30, 2016, respectively. We discuss the impact further in Note 12.

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(1)

During the fourth quarter of 2016, we received additional information regarding GdC’s deferred income taxes as of the acquisition date, primarily related to basis differences in GdC’s property, plant and equipment. 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)	We expect acquired accounts receivable to be substantially realizable in cash. Accounts receivable are net of negligible collection allowances.

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▪	PP&E – We applied an income approach utilizing market based discounted cash flows. We utilized the pricing included in the existing power purchase agreements, 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 20 years, reflecting the life of the transmission and consumption transmission permit.

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

▪	Derivatives – Utilizing 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 GdC 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 GdC 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 GdC 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

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▪	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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▪	EnergySouth

▪	Energía Sierra Juárez

▪	Broken Bow 2 Wind

▪	Copper Mountain Solar 3

▪	Cameron LNG, LLC

(1)	Included in Gain on Sale of Assets on our Consolidated Statements of Operations.

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(1)	Includes losses on forward exchange contracts entered into to manage the foreign currency exchange rate risk of the Chilean Unidad de Fomento (CLF) relative to the U.S. dollar, related to certain construction commitments that are denominated in CLF. The 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.

(3)	The carrying value of our equity method investment was $65 million higher than the underlying equity in the net assets of the investee due to equity method goodwill at December 31, 2015.

(4)	The carrying value of our equity method investment is $190 million and $143 million higher than the underlying equity in the net assets of the investee at December 31, 2016 and 2015, respectively, primarily due to guarantees, which we discuss below, and interest capitalized on the investment, as the joint venture has not commenced its planned principal operations.

(5)	The carrying value of our equity method investment at December 31, 2015 was $357 million lower than the underlying equity in the net assets of the investee due to an impairment charge recorded in 2012.

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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 effective income tax rate.

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(1)	On September 26, 2016, IEnova completed the acquisition of PEMEX’s 50-percent interest in GdC, 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, GdC and Rockies Express are no longer equity method investments.

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▪	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, 2016.

▪	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)	Early redemption or deconsolidated in 2016.

(3)	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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▪	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

▪	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.

(1)

U.S. pretax book income decreased in 2016 at the California Utilities primarily due to the reallocation of prior years’ income tax benefits generated from income tax repairs deductions to ratepayers pursuant to the 2016 GRC FD, as we discuss in Note 14; at Sempra LNG & Midstream for the loss on permanent release of pipeline capacity, as we discuss in Note 15; and the impairment charge related to the investment in Rockies Express, as we discuss in Note 3. Non-U.S. pretax book income increased in 2016 primarily due to the noncash gain associated with the remeasurement of our equity interest in GdC, as we discuss in Note 3.

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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, 2016 and 2015, includes $234 million and $120 million, respectively, recorded as a noncurrent asset and $3,745 million and $3,157 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 other postretirement benefit plans in the year in which the changes occur. Generally, those changes are reported in other comprehensive income and as a separate component of shareholders’ equity.

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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 and 7.75 percent in 2015 and 2014, respectively; the ultimate trend was 5.00 percent in 2015 and 2014; and the year the rate reaches the ultimate trend was 2022 and 2020 in 2015 and 2014, respectively. For Chilquinta Energía, the health care cost trend rate assumed for next year, and the ultimate trend, was 3.00 percent in each of 2016, 2015 and 2014.

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▪	38 percent domestic equity

▪	26 percent international equity

▪	18 percent long credit

▪	8 percent ultra-long duration government securities

▪	5 percent global high yield credit

▪	5 percent real assets

▪	long-term cost

▪	variability and level of contributions

▪	funded status

▪	a range of expected outcomes over varying confidence levels

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(1)	Reflects the retrospective adoption of ASU 2015-07 as of January 1, 2016, as we discuss in Note 2. Prior to adoption,

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

(3)	Excludes cash and cash equivalents of $14 million and accounts payable of $25 million.

(4)	Excludes transfers receivable from other plans of $2 million at SDG&E.

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(1)	Reflects the retrospective adoption of ASU 2015-07 as of January 1, 2016, as we discuss in Note 2. Prior to adoption,

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

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

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

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(1)	Reflects the retrospective adoption of ASU 2015-07 as of January 1, 2016, as we discuss in Note 2. Prior to adoption,

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

(3)	Excludes cash and cash equivalents of $3 million and accounts payable of $4 million held in SoCalGas PBOP plan trusts.

(4)	Excludes cash and cash equivalents of $4 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 (RSAs)

▪	restricted stock units (RSUs)

▪	stock appreciation rights

▪	performance awards

▪	stock payments

▪	dividend equivalents

▪

Non-Qualified Stock Options: Options have an exercise price equal to the market price of the common stock at the date of grant, are service-based, become exercisable over a four-year period, and expire 10 years from the date of grant. Vesting and/or the ability to exercise may be accelerated upon a change in control, in accordance with severance pay agreements, in accordance with the terms of the grant, or upon eligibility for retirement. Options are subject to forfeiture or earlier expiration when an employee terminates employment.

▪

Performance-Based Restricted Stock Units: These 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 Standard & Poor’s (S&P) 500 Utilities Index and the S&P 500 Index. We primarily use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies to develop our 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 during or after 2015 that vest based on Sempra Energy’s total return to shareholders, a modifier adds 20 percent to the award’s payout (as initially calculated based on total return to shareholders relative to that of specified market indices) for total shareholder return performance in the top quartile relative to historical benchmark data for Sempra Energy and reduces the award’s payout by 20 percent for performance in the bottom quartile. However, in no event will more than an additional 100 percent of the granted 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.

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▪	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.

◦	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 are generally exercisable 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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▪	$8 million in 2016

▪	$12 million in 2015

▪	$33 million in 2014

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(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 congestion revenue rights (CRRs), which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations.

▪

Sempra Mexico, 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 also uses natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its Mexican distribution operations. These derivatives, which are

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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.

(1)	Million British thermal units

(2)	Megawatt hours

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

(2)	At December 31, 2016, includes GdC, which was previously a joint venture and excluded from this table until we acquired the remaining 50-percent interest in September 2016.

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(1)	At December 31, 2016, includes GdC, which was previously a joint venture and excluded from this table until we acquired the remaining 50-percent interest in September 2016.

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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. There were gains of $9 million from hedge ineffectiveness in 2014. All other changes in the fair value of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and recorded in Other Income, Net.

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

(2)	There was $4 million, $2 million and $1 million of losses from ineffectiveness related to these cash flow hedges in 2016, 2015 and 2014, respectively.

(3)	There was negligible hedge ineffectiveness related to these cash flow hedges at SDG&E in 2016, 2015 and 2014.

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▪

Nuclear decommissioning trusts reflect the assets of SDG&E’s nuclear decommissioning trusts, excluding cash balances. A third party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Equity and certain debt securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other debt securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).

▪

For commodity contracts, interest rate derivatives and foreign exchange instruments, we primarily use a market approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below 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, 2016 and 2015.

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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

(2)	Excludes cash balances and cash equivalents.

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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

(2)	Excludes cash balances and cash equivalents.

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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

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(1)	Excluding accumulated interest outstanding of $17 million and $11 million at December 31, 2016 and 2015, respectively.

(2)	Before reductions for unamortized discount (net of premium) and debt issuance costs of $109 million and $107 million at December 31, 2016

(3)	Level 3 instruments include $305 million and $315 million at December 31, 2016 and 2015, respectively, related to Otay Mesa VIE.

(4)	Before reductions for unamortized discount and debt issuance costs of $45 million and $43 million at December 31, 2016 and 2015,

(5)	Before reductions for unamortized discount and debt issuance costs of $27 million and $24 million at December 31, 2016 and 2015,

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

(2)	At measurement date of September 29, 2016. At December 31, 2016, TdM has a carrying value of $154 million, reflecting subsequent

(3)	At measurement date of July 16, 2014. At December 31, 2016, our investment in Energía Sierra Juárez had a carrying value of $38 million, reflecting subsequent equity method activity to record distributions and earnings.

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(1)	Includes average fully vested RSUs held in our Deferred Compensation Plan of 568 in 2016, 491 in 2015 and 212 in 2014. 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)	Reflects the prospective adoption of ASU 2016-09 as of January 1, 2016. Prior to the adoption, the dilutive effect of stock options, RSAs and RSUs was reduced by excess tax benefits assumed to be used to repurchase shares on the open market.

(3)	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.

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

(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 rate of return or SONGS ROR)

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(1)	Maturity dates are 2017-2047.

(2)	Maturity dates are 2017-2115.

(3)	Maturity dates are 2017-2111.

(1)	Excludes securities that are held to maturity.

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(1)	At both December 31, 2016 and 2015, the net receivable at SDG&E and the net payable at SoCalGas are shown separately on Sempra Energy’s Consolidated Balance Sheets.

(2)	Long-term undercollected balance is included in Regulatory Assets (long-term) on Sempra Energy’s Consolidated Balance Sheets and in Other Regulatory Assets (long-term) on SoCalGas’ Consolidated Balance Sheets.

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(1)	Regulatory assets earning a rate of return.

(2)	Represents cumulative amounts collected in rates for future nonlegal asset removal costs.

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(1)	At Sempra Energy Consolidated, included in Other Current Assets.

(2)	Excludes long-term undercollected balancing accounts at December 31, 2016 and 2015 of $85 million and $215 million, respectively, recorded at Sempra Energy Consolidated as Regulatory Assets (long-term) and at SoCalGas as Other Regulatory Assets (long-term).

(3)	Included in Other Current Liabilities.

(4)	At December 31, 2016 and 2015, $179 million and $72 million, respectively, at Sempra Energy Consolidated and $179 million and $71 million, respectively, at SoCalGas are included in Deferred Credits and Other.

▪	Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts.

▪	Regulatory assets arising from the SONGS plant closure are associated with SDG&E’s investment in SONGS as of the plant closure date and the cost of operations since Units 2 and 3 were taken offline, as we discuss further in Note 13.

▪

Regulatory assets recorded to the Wildfire Expense Memorandum Account (WEMA) arising from CPUC-related costs for wildfire litigation are costs in excess of liability insurance coverage and amounts recovered from third parties, and are subject to CPUC review for reasonableness and assessment of SDG&E’s prudence surrounding the settlement of claims in connection with the 2007 wildfires. We discuss the 2007 wildfires in Note 15 in “SDG&E – 2007 Wildfire Litigation.”

▪

Deferred taxes recoverable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Mexico expect to recover net regulatory assets related to deferred income taxes over the lives of the assets that give rise to the accumulated deferred income tax liabilities. Regulatory assets include certain income tax benefits associated with flow-through repair allowance deductions, which we discuss further below.

▪	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.

▪	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 11 years for SDG&E and from 5 years to 9 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 is recovering this asset over a remaining 1-year period in rate base.

▪	The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining 53-year period. We discuss the trust further in Note 15.

▪	The regulatory asset related to workers’ compensation represents accrued costs for future claims that will be recovered from customers in future rates as expenditures are made.

▪	Amortization expense on regulatory assets for the years ended December 31, 2016, 2015 and 2014 was $65 million, $62 million and $20 million, respectively, at Sempra Energy Consolidated, $63 million, $60 million and $18 million, respectively, at SDG&E, and $2 million in each year at SoCalGas.

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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 LNG purchase agreements discussed below.

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▪	Long-term contracts: 40 percent (of which 35 percent is provided by renewable energy contracts expiring on various dates through 2041)

▪	Other SDG&E-owned generation and tolling contracts (including OMEC): 45 percent

▪	Spot market purchases: 15 percent

(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.

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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 $8 million in Current Portion of Long-Term Debt and $231 million in Long-Term Debt on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets at December 31, 2016. Of the present value of net minimum lease payments, $500 million will be recorded as a capital lease obligation when construction of the peaker plant facility is completed and delivery of contracted power commences, which is scheduled to occur in June 2017.

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▪	$80 million for infrastructure improvements for natural gas and electric transmission and distribution operations;

▪	$49 million for the engineering, material procurement and construction costs primarily associated with the San Luis Rey Synchronous Condenser and Bay Boulevard Substation relocation projects; and

▪	$14 million related to spent fuel management at SONGS.

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

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

(1)	Sites for which we have been identified as a Potentially Responsible Party.

(2)	Includes $8 million, $1 million and $7 million classified as current liabilities, and $20 million, $1 million and $18 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 mitigation.

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

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

▪	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.

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▪

Sempra Mexico develops, owns and operates, or holds interests in, natural gas transmission systems and an ethane system, a liquid petroleum gas pipeline and associated storage terminal, a natural gas distribution utility, electric generation facilities (including wind and solar electric generation facilities and a natural gas-fired power plant), a terminal for the import of LNG, and marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico. 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 United States.

▪

Sempra LNG & Midstream develops, owns and operates, or holds interests in, natural gas pipelines and storage facilities and a terminal for the import and export of LNG and sale of natural gas, all within the United States. 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 $6 million, $76 million, $102 million, and $180 million for 2016, $9 million, $75 million, $101 million and $192 million for 2015, and $10 million, $69 million, $91 million and $342 million for 2014 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)	Reflects the prospective adoption of ASU 2016-09 effective January 1, 2016, as we discuss in Note 2.

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

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(1)	Reflects the prospective adoption of ASU 2016-09 effective January 1, 2016, as we discuss in Note 2.

(1)	Reflects the prospective adoption of ASU 2016-09 effective January 1, 2016, as we discuss in Note 2.

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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 13(a)-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 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 13(a)-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 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 13(a)-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 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 13(a)-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 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 13(a)-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 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 13(a)-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 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, 2016 (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, 2016 (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, 2016 (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, 2016 (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, 2016 (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, 2016 (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.