SEMPRA - Interim / Quarterly Report 2018

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended	September 30, 2018
	or
[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from	to
Commission File No.	Exact Name of Registrants as Specified in their Charters, Address and Telephone Number	State of Incorporation	I.R.S. Employer Identification Nos.	Former name, former address and former fiscal year, if changed since last report
1-14201	SEMPRA ENERGY	California	33-0732627	No change
	488 8 th Avenue
	San Diego, California 92101
	(619) 696-2000
1-03779	SAN DIEGO GAS & ELECTRIC COMPANY	California	95-1184800	No change
	8326 Century Park Court
	San Diego, California 92123
	(619) 696-2000
1-01402	SOUTHERN CALIFORNIA GAS COMPANY	California	95-1240705	No change
	555 West Fifth Street
	Los Angeles, California 90013
	(213) 244-1200

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. — Yes	X	No

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit such files). — Yes
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

	Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller reporting company	Emerging growth company
Sempra Energy	[ X ]	[ ]	[ ]	[ ]	[ ]
San Diego Gas & Electric Company	[ ]	[ ]	[ X ]	[ ]	[ ]
Southern California Gas Company	[ ]	[ ]	[ X ]	[ ]	[ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. — Sempra Energy	Yes	No
San Diego Gas & Electric Company	Yes	No
Southern California Gas Company	Yes	No
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Sempra Energy	Yes	No	X
San Diego Gas & Electric Company	Yes	No	X
Southern California Gas Company	Yes	No	X
Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.
Common stock outstanding on November 1, 2018:

Sempra Energy	273,660,222 shares
San Diego Gas & Electric Company	Wholly owned by Enova Corporation, which is wholly owned by Sempra Energy
Southern California Gas Company	Wholly owned by Pacific Enterprises, which is wholly owned by Sempra Energy

SEMPRA ENERGY FORM 10-Q SAN DIEGO GAS & ELECTRIC COMPANY FORM 10-Q SOUTHERN CALIFORNIA GAS COMPANY FORM 10-Q TABLE OF CONTENTS
		Page
Information Regarding Forward-Looking Statements		6
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	105
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	151
Item 4.	Controls and Procedures	152
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	152
Item 1A.	Risk Factors	152
Item 6.	Exhibits	154
Signatures		157

This combined Form 10-Q is separately filed by Sempra Energy, San Diego Gas & Electric Company and Southern California Gas Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representation whatsoever as to any other company.

You should read this report in its entirety as it pertains to each respective reporting company. No one section of the report deals with all aspects of the subject matter. Separate Part I – Item 1 sections are provided for each reporting company, except for the Notes to Condensed Consolidated Financial Statements. The Notes to Condensed Consolidated Financial Statements for all of the reporting companies are combined. All Items other than Part I – Item 1 are combined for the reporting companies.

The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

GLOSSARY
2016 GRC FD	final decision in the California Utilities’ 2016 General Rate Case
AB	Assembly Bill
AFUDC	allowance for funds used during construction
Annual Report	Annual Report on Form 10-K for the year ended December 31, 2017
AOCI	accumulated other comprehensive income (loss)
ASC	Accounting Standards Codification
Asset Exchange Agreement	agreement and plan of merger among Oncor, SDTS and SU
ASU	Accounting Standards Update
Bay Gas	Bay Gas Storage Company, Ltd.
Bcf	billion cubic feet
BP	British Petroleum or its subsidiaries
bps	basis points
Cal PA	California Public Advocates Office (formerly known as ORA)
California Utilities	San Diego Gas & Electric Company and Southern California Gas Company, collectively
Cameron LNG JV	Cameron LNG Holdings, LLC
CARB	California Air Resources Board
CCA	Community Choice Aggregation
CCM	cost of capital adjustment mechanism
CEC	California Energy Commission
CEQA	California Environmental Quality Act
CFE	Comisión Federal de Electricidad (Federal Electricity Commission in Mexico)
Chevron	Chevron Corporation or its subsidiaries
Chilquinta Energía	Chilquinta Energía S.A. and its subsidiaries
COFECE	Comisión Federal de Competencia Económica (Mexican Competition Commission)
Con Ed	Consolidated Edison, Inc.
CNE	Comisión Nacional de Energía (National Energy Commission) (Chile)
CPUC	California Public Utilities Commission
CRE	Comisión Reguladora de Energía (Energy Regulatory Commission in Mexico)
CRR	congestion revenue right
DA	Direct Access
DEN	Ductos y Energéticos del Norte, S. de R.L. de C.V.
DOE	U.S. Department of Energy
DOGGR	California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources
DPH	Los Angeles County Department of Public Health
Dth	dekatherm
ECA	Energía Costa Azul
Ecogas	Ecogas México, S. de R.L. de C.V.
Edison	Southern California Edison Company, a subsidiary of Edison International
EFH	Energy Future Holdings Corp. (renamed Sempra Texas Holdings Corp.)
EFIH	Energy Future Intermediate Holding Company LLC (renamed Sempra Texas Intermediate Holding Company LLC)
EIR	environmental impact review
Eletrans	Eletrans S.A., Eletrans II S.A. and Eletrans III S.A., collectively
EPA	U.S. Environmental Protection Agency
EPC	engineering, procurement and construction
EPS	earnings per common share
ERCOT	Electric Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas
ETR	effective income tax rate
FERC	Federal Energy Regulatory Commission
FTA	Free Trade Agreement
GHG	greenhouse gas
GRC	General Rate Case
HLBV	hypothetical liquidation at book value
HMRC	United Kingdom’s Revenue and Customs Department
IEnova	Infraestructura Energética Nova, S.A.B. de C.V.
IMG	Infraestructura Marina del Golfo

GLOSSARY (CONTINUED)
InfraREIT	InfraREIT, Inc.
InfraREIT Merger Agreement	agreement and plan of merger among Oncor, 1912 Merger Sub LLC (a wholly owned subsidiary of Oncor), Oncor T&D Partners, LP (a wholly owned indirect subsidiary of Oncor), InfraREIT and InfraREIT Partners
InfraREIT Partners	InfraREIT Partners, LP
IRC	U.S. Internal Revenue Code of 1986 (as amended)
IRS	Internal Revenue Service
ISFSI	independent spent fuel storage installation
ISO	Independent System Operator
JP Morgan	J.P. Morgan Chase & Co.
km	kilometer
kV	kilovolt
LA Storage	LA Storage, LLC
LA Superior Court	Los Angeles County Superior Court
the Leak	the leak at the SoCalGas Aliso Canyon natural gas storage facility injection-and-withdrawal well, SS25, discovered by SoCalGas on October 23, 2015
LNG	liquefied natural gas
LPG	liquid petroleum gas
Luz del Sur	Luz del Sur S.A.A. and its subsidiaries
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Merger	The merger of EFH with an indirect subsidiary of Sempra Energy, with EFH continuing as the surviving company and as an indirect, wholly owned subsidiary of Sempra Energy
Merger Agreement	Agreement and Plan of Merger dated August 21, 2017, as supplemented by a Waiver Agreement dated October 3, 2017 and an amendment dated February 15, 2018, between Sempra Energy, EFH, EFIH and an indirect subsidiary of Sempra Energy
Merger Consideration	Pursuant to the Merger Agreement, Sempra Energy paid consideration of $9.45 billion in cash
MHI	Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc., collectively
Mississippi Hub	Mississippi Hub, LLC
MMBtu	million British thermal units (of natural gas)
Moody’s	Moody’s Investors Service
MOU	Memorandum of Understanding
Mtpa	million tonnes per annum
MW	megawatt
MWh	megawatt hour
NAFTA	North American Free Trade Agreement
NCI	noncontrolling interest(s)
NDT	nuclear decommissioning trusts
NEIL	Nuclear Electric Insurance Limited
NOL	net operating loss
NRC	Nuclear Regulatory Commission
OCI	other comprehensive income (loss)
OII	Order Instituting Investigation
OIR	Order Instituting a Rulemaking
O&M	operation and maintenance expense
OMEC	Otay Mesa Energy Center
OMEC LLC	Otay Mesa Energy Center LLC
OMI	Oncor Management Investment LLC
Oncor	Oncor Electric Delivery Company LLC
Oncor Holdings	Oncor Electric Delivery Holdings Company LLC
ORA	CPUC Office of Ratepayer Advocates (now known as Cal PA)
Otay Mesa VIE	OMEC LLC VIE
PEMEX	Petróleos Mexicanos (Mexican state-owned oil company)
PG&E	Pacific Gas and Electric Company
PHMSA	Pipeline and Hazardous Materials Safety Administration
PPA	power purchase agreement
PSEP	Pipeline Safety Enhancement Plan
PSRP	Pipeline Safety & Reliability Project
PUCT	Public Utility Commission of Texas
PURA	Public Utility Regulatory Act
RAMP	Risk Assessment Mitigation Phase
RBS	The Royal Bank of Scotland plc

GLOSSARY (CONTINUED)
RBS SEE	RBS Sempra Energy Europe
RBS Sempra Commodities	RBS Sempra Commodities LLP
ROE	return on equity
RSA	restricted stock award
RSU	restricted stock unit
SB	Senate Bill
SCAQMD	South Coast Air Quality Management District
SDG&E	San Diego Gas & Electric Company
SDTS	Sharyland Distribution & Transmission Services, L.L.C. (a subsidiary of InfraREIT)
SEC	U.S. Securities and Exchange Commission
Securities Purchase Agreement	securities purchase agreement among SU, SU Investment Partners, L.P., Sempra Texas Utilities Holdings I, LLC (a wholly owned subsidiary of Sempra Energy) and Sempra Energy
SEDATU	Secretaría de Desarrollo Agrario, Territorial y Urbano (Mexican agency in charge of agriculture, land and urban development)
Sempra Global	holding company for most of Sempra Energy’s subsidiaries not subject to California or Texas utility regulation
series A preferred stock	6% mandatory convertible preferred stock, series A
series B preferred stock	6.75% mandatory convertible preferred stock, series B
SFP	secondary financial protection
SGRP	Steam Generator Replacement Project
SoCalGas	Southern California Gas Company
SONGS	San Onofre Nuclear Generating Station
SONGS OII	CPUC’s Order Instituting Investigation into the SONGS Outage
S&P	Standard & Poor’s
SU	Sharyland Utilities, LP
TAG	TAG Pipelines Norte, S. de R.L. de C.V.
TCJA	Tax Cuts and Jobs Act of 2017
TdM	Termoeléctrica de Mexicali
Tecnored	Tecnored S.A.
Tecsur	Tecsur S.A.
TTI	Texas Transmission Investment LLC
TURN	The Utility Reform Network
U.S. GAAP	accounting principles generally accepted in the United States of America
VAT	value-added tax
VIE	variable interest entity

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

We make statements in this report that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based upon assumptions with respect to the future, involve risks and uncertainties, and are not guarantees of performance. Future results may differ materially from those expressed in the forward-looking statements. These forward-looking statements represent our estimates and assumptions only as of the filing date of this report. We assume no obligation to update or revise any forward-looking statement as a result of new information, future events or other factors.

In this report, when we use words such as “believes,” “expects,” “anticipates,” “plans,” “estimates,” “projects,” “forecasts,” “contemplates,” “assumes,” “depends,” “should,” “could,” “would,” “will,” “confident,” “may,” “can,” “potential,” “possible,” “proposed,” “target,” “pursue,” “outlook,” “maintain,” or similar expressions, or when we discuss our guidance, strategy, plans, goals, vision, opportunities, projections, initiatives, objectives or intentions, we are making forward-looking statements.

Factors, among others, that could cause our actual results and future actions to differ materially from those described in any forward-looking statements include risks and uncertainties relating to:

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

▪ the timing and success of business development efforts, major acquisitions such as our interest in Oncor, and construction projects, including risks in (i) timely obtaining or maintaining permits and other authorizations, (ii) completing construction projects on schedule and on budget, (iii) obtaining the consent and participation of partners and counterparties and their ability to fulfill contractual commitments, and (iv) not realizing anticipated benefits;

▪ 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; denial of approvals of proposed settlements; and delays in, or disallowance or denial of, regulatory agency authorizations to recover costs in rates from customers or regulatory agency approval for projects required to enhance safety and reliability; and moves to reduce or eliminate reliance on natural gas;

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

▪ the availability of electric power and natural gas and natural gas storage capacity, including disruptions caused by failures in the transmission grid, limitations on the withdrawal or injection of natural gas from or into storage facilities, and equipment failures;

▪ risks posed by actions of third parties who control the operations of our investments;

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

▪ 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;

▪ our ability to successfully execute our plan to divest certain non-utility assets within the anticipated timeframe, if at all, or that such plan may not yield the anticipated benefits;

▪ actions of activist shareholders, which could impact the market price of our equity and debt securities and disrupt our operations as a result of, among other things, requiring significant time and attention by management and our board of directors;

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

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

▪ actions by credit rating agencies to downgrade our credit ratings or those of our subsidiaries or to place those ratings on negative outlook and our ability to borrow at favorable interest rates;

▪ changes in foreign and domestic trade policies and laws, including border tariffs, and revisions to or replacement of international trade agreements, such as NAFTA, that may increase our costs or impair our ability to resolve trade disputes;

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

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

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

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

▪ Oncor’s ability to eliminate or reduce its quarterly dividends due to regulatory capital requirements and commitments, or the determination by Oncor’s independent directors or a minority member director to retain such amounts to meet future requirements; and

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

We caution you not to rely unduly on any forward-looking statements. You should review and consider carefully the risks, uncertainties and other factors that affect our business as described herein, in our most recent Annual Report and in other reports that we file with the SEC.

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017 (1)		2018		2017 (1)
	(unaudited)
REVENUES
Utilities	$ 2,460		$ 2,277		$ 7,248		$ 7,172
Energy-related businesses	480		402		1,218		1,071
Total revenues	2,940		2,679		8,466		8,243
EXPENSES AND OTHER INCOME
Utilities:
Cost of electric fuel and purchased power	( 675	)	( 650	)	( 1,778	)	( 1,730	)
Cost of natural gas	( 255	)	( 190	)	( 782	)	( 903	)
Energy-related businesses:
Cost of natural gas, electric fuel and purchased power	( 119	)	( 97	)	( 257	)	( 226	)
Other cost of sales	( 17	)	( 21	)	( 54	)	( 5	)
Operation and maintenance	( 819	)	( 759	)	( 2,383	)	( 2,226	)
Depreciation and amortization	( 380	)	( 378	)	( 1,158	)	( 1,106	)
Franchise fees and other taxes	( 131	)	( 114	)	( 352	)	( 325	)
Write-off of wildfire regulatory asset	—		( 351	)	—		( 351	)
Impairment losses	( 4	)	( 1	)	( 1,304	)	( 72	)
Other income, net	97		40		196		322
Interest income	22		12		76		26
Interest expense	( 232	)	( 165	)	( 685	)	( 493	)
Income (loss) before income taxes and equity earnings of unconsolidated subsidiaries	427		5		( 15	)	1,154
Income tax (expense) benefit	( 167	)	84		127		( 378	)
Equity earnings	74		13		50		26
Net income	334		102		162		802
Earnings attributable to noncontrolling interests	( 24	)	( 45	)	( 12	)	( 44	)
Mandatory convertible preferred stock dividends	( 36	)	—		( 89	)	—
Preferred dividends of subsidiary	—		—		( 1	)	( 1	)
Earnings attributable to common shares	$ 274		$ 57		$ 60		$ 757
Basic earnings per common share	$ 1.00		$ 0.23		$ 0.23		$ 3.01
Weighted-average number of shares outstanding, basic (thousands)	273,944		251,692		265,963		251,425
Diluted earnings per common share	$ 0.99		$ 0.22		$ 0.22		$ 2.99
Weighted-average number of shares outstanding, diluted (thousands)	275,907		253,364		267,644		252,987

(1) As adjusted for the retrospective adoption of ASU 2017-07, which we discuss in Note 2, and a reclassification to conform to current year presentation, which we discuss in Note 1.

See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Sempra Energy shareholders’ equity
	Pretax amount		Income tax (expense) benefit		Net-of-tax amount		Noncontrolling interests (after-tax)		Total
	(unaudited)
	Three months ended September 30, 2018 and 2017
2018:
Net income	$ 477		$ ( 167	)	$ 310		$ 24		$ 334
Other comprehensive income (loss):
Foreign currency translation adjustments	( 16	)	—		( 16	)	( 2	)	( 18	)
Financial instruments	22		( 7	)	15		4		19
Pension and other postretirement benefits	( 14	)	4		( 10	)	—		( 10	)
Total other comprehensive (loss) income	( 8	)	( 3	)	( 11	)	2		( 9	)
Comprehensive income	$ 469		$ ( 170	)	$ 299		$ 26		$ 325
2017:
Net (loss) income	$ ( 27	)	$ 84		$ 57		$ 45		$ 102
Other comprehensive income (loss):
Foreign currency translation adjustments	27		—		27		( 1	)	26
Financial instruments	7		( 1	)	6		8		14
Pension and other postretirement benefits	11		( 4	)	7		—		7
Total other comprehensive income	45		( 5	)	40		7		47
Comprehensive income	$ 18		$ 79		$ 97		$ 52		$ 149

	Nine months ended September 30, 2018 and 2017
2018:
Net income	$ 23		$ 127		$ 150		$ 12		$ 162
Other comprehensive income (loss):
Foreign currency translation adjustments	( 78	)	—		( 78	)	( 5	)	( 83	)
Financial instruments	145		( 45	)	100		20		120
Pension and other postretirement benefits	( 8	)	3		( 5	)	—		( 5	)
Total other comprehensive income	59		( 42	)	17		15		32
Comprehensive income	82		85		167		27		194
Preferred dividends of subsidiary	( 1	)	—		( 1	)	—		( 1	)
Comprehensive income, after preferred
dividends of subsidiary	$ 81		$ 85		$ 166		$ 27		$ 193
2017:
Net income	$ 1,136		$ ( 378	)	$ 758		$ 44		$ 802
Other comprehensive income (loss):
Foreign currency translation adjustments	76		—		76		10		86
Financial instruments	( 29	)	13		( 16	)	6		( 10	)
Pension and other postretirement benefits	16		( 6	)	10		—		10
Total other comprehensive income	63		7		70		16		86
Comprehensive income	1,199		( 371	)	828		60		888
Preferred dividends of subsidiary	( 1	)	—		( 1	)	—		( 1	)
Comprehensive income, after preferred
dividends of subsidiary	$ 1,198		$ ( 371	)	$ 827		$ 60		$ 887

See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	September 30, 2018		December 31, 2017 (1)
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$ 212		$ 288
Restricted cash	73		62
Accounts receivable – trade, net	1,252		1,307
Accounts receivable – other, net	411		277
Due from unconsolidated affiliates	43		37
Income taxes receivable	99		110
Inventories	345		307
Regulatory assets	92		325
Fixed-price contracts and other derivatives	96		66
Greenhouse gas allowances	339		299
Assets held for sale	1,881		127
Other	202		136
Total current assets	5,045		3,341
Other assets:
Restricted cash	3		14
Due from unconsolidated affiliates	682		598
Regulatory assets	1,469		1,517
Nuclear decommissioning trusts	1,042		1,033
Investment in Oncor Holdings	9,553		—
Other investments	2,561		2,527
Goodwill	2,363		2,397
Other intangible assets	229		596
Dedicated assets in support of certain benefit plans	443		455
Insurance receivable for Aliso Canyon costs	474		418
Deferred income taxes	116		170
Greenhouse gas allowances	275		93
Sundry	852		792
Total other assets	20,062		10,610
Property, plant and equipment:
Property, plant and equipment	47,734		48,108
Less accumulated depreciation and amortization	( 12,236	)	( 11,605	)
Property, plant and equipment, net ($302 and $321 at September 30, 2018 and December 31, 2017, respectively, related to Otay Mesa VIE)	35,498		36,503
Total assets	$ 60,605		$ 50,454

(1) Derived from audited financial statements.

See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	September 30, 2018		December 31, 2017 (1)
	(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$ 2,897		$ 1,540
Accounts payable – trade	1,199		1,350
Accounts payable – other	176		173
Due to unconsolidated affiliates	7		7
Dividends and interest payable	495		342
Accrued compensation and benefits	356		439
Regulatory liabilities	284		109
Current portion of long-term debt ($287 and $10 at September 30, 2018 and December 31, 2017, respectively, related to Otay Mesa VIE)	1,464		1,427
Fixed-price contracts and other derivatives	63		109
Customer deposits	172		162
Reserve for Aliso Canyon costs	161		84
Greenhouse gas obligations	339		299
Liabilities held for sale	156		49
Other	722		545
Total current liabilities	8,491		6,635
Long-term debt ($284 at December 31, 2017 related to Otay Mesa VIE)	21,335		16,445
Deferred credits and other liabilities:
Customer advances for construction	146		150
Due to unconsolidated affiliates	36		35
Pension and other postretirement benefit plan obligations, net of plan assets	1,052		1,148
Deferred income taxes	2,231		2,767
Deferred investment tax credits	25		28
Regulatory liabilities	3,974		3,922
Asset retirement obligations	2,750		2,732
Fixed-price contracts and other derivatives	235		316
Greenhouse gas obligations	102		—
Deferred credits and other	1,117		1,136
Total deferred credits and other liabilities	11,668		12,234
Commitments and contingencies (Note 11)
Equity:
Preferred stock (50 million shares authorized):
6% mandatory convertible preferred stock, series A (17.25 million shares issued and outstanding at September 30, 2018)	1,693		—
6.75% mandatory convertible preferred stock, series B (5.75 million shares issued and outstanding at September 30, 2018)	566		—
Common stock (750 million shares authorized; 274 million and 251 million shares outstanding at September 30, 2018 and December 31, 2017, respectively; no par value)	5,485		3,149
Retained earnings	9,485		10,147
Accumulated other comprehensive income (loss)	( 612	)	( 626	)
Total Sempra Energy shareholders ’ equity	16,617		12,670
Preferred stock of subsidiary	20		20
Other noncontrolling interests	2,474		2,450
Total equity	19,111		15,140
Total liabilities and equity	$ 60,605		$ 50,454

(1) Derived from audited financial statements.

See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Nine months ended September 30,
	2018		2017 (1)
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 162		$ 802
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,158		1,106
Deferred income taxes and investment tax credits	( 289	)	302
Write-off of wildfire regulatory asset	—		351
Impairment losses	1,304		72
Equity earnings	( 50	)	( 26	)
Fixed-price contracts and other derivatives	( 44	)	( 142	)
Other	139		18
Net change in other working capital components	444		229
Insurance receivable for Aliso Canyon costs	( 56	)	64
Changes in other noncurrent assets and liabilities, net	( 177	)	( 72	)
Net cash provided by operating activities	2,591		2,704
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	( 2,815	)	( 2,880	)
Expenditures for investments and acquisitions	( 9,921	)	( 110	)
Proceeds from sale of assets	7		12
Distributions from investments	9		25
Purchases of nuclear decommissioning trust assets	( 703	)	( 1,082	)
Proceeds from sales of nuclear decommissioning trust assets	703		1,082
Advances to unconsolidated affiliates	( 84	)	( 321	)
Repayments of advances to unconsolidated affiliates	71		8
Other	29		6
Net cash used in investing activities	( 12,704	)	( 3,260	)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	( 645	)	( 561	)
Preferred dividends paid	( 53	)	—
Preferred dividends paid by subsidiary	( 1	)	( 1	)
Issuances of mandatory convertible preferred stock, net of $41 in offering costs	2,259		—
Issuances of common stock, net of $41 in offering costs in 2018	2,261		37
Repurchases of common stock	( 20	)	( 15	)
Issuances of debt (maturities greater than 90 days)	8,628		2,395
Payments on debt (maturities greater than 90 days)	( 2,967	)	( 1,829	)
Increase in short-term debt, net	707		475
Proceeds from sales of noncontrolling interest, net of $1 in offering costs	90		—
Net distributions to noncontrolling interests	( 101	)	( 109	)
Settlement of cross-currency swaps	( 33	)	—
Other	( 80	)	( 11	)
Net cash provided by financing activities	10,045		381
Effect of exchange rate changes on cash, cash equivalents and restricted cash	( 8	)	11
Decrease in cash, cash equivalents and restricted cash	( 76	)	( 164	)
Cash, cash equivalents and restricted cash, January 1	364		425
Cash, cash equivalents and restricted cash, September 30	$ 288		$ 261

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

See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
	Nine months ended September 30,
	2018		2017 (1)
	(unaudited)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$ 584		$ 414
Income tax payments, net of refunds	120		126
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Acquisition:
Assets acquired	$ 9,670		$ —
Liabilities assumed	( 104	)	—
Cash paid	$ 9,566		$ —
Accrued capital expenditures	$ 424		$ 476
Accrued Merger-related transaction and financing costs	—		21
Increase in capital lease obligations for investment in property, plant and equipment	9		502
Equitization of note receivable due from unconsolidated affiliate	—		19
Preferred dividends declared but not paid	36		—
Common dividends issued in stock	41		40
Common dividends declared but not paid	252		214

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

See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Dollars in millions)
	Preferred stock	Common stock	Retained earnings	Accumulated other comprehensive income (loss)		Sempra Energy shareholders' equity		Non- controlling interests		Total equity
	(unaudited)
	Three months ended September 30, 2018
Balance at June 30, 2018	$ 1,693	$ 5,279	$ 9,455	$ ( 601	)	$ 15,826		$ 2,538		$ 18,364
Net income			310			310		24		334
Other comprehensive (loss) income				( 11	)	( 11	)	2		( 9	)
Share-based compensation expense		17				17				17
Dividends declared:
Series A preferred stock ($1.50/share)			( 26	)		( 26	)			( 26	)
Series B preferred stock ($1.73/share)			( 10	)		( 10	)			( 10	)
Common stock ($0.90/share)			( 244	)		( 244	)			( 244	)
Issuance of series B preferred stock	566					566				566
Issuances of common stock		185				185				185
Noncontrolling interest activities:
Equity contributions								2		2
Distributions								( 86	)	( 86	)
Sales, net of offering costs		4				4		1		5
Increase from acquisition								13		13
Balance at September 30, 2018	$ 2,259	$ 5,485	$ 9,485	$ ( 612	)	$ 16,617		$ 2,494		$ 19,111
	Three months ended September 30, 2017
Balance at June 30, 2017	$ —	$ 3,046	$ 11,004	$ ( 718	)	$ 13,332		$ 2,273		$ 15,605
Net income			57			57		45		102
Other comprehensive income				40		40		7		47
Share-based compensation expense		21				21				21
Dividends declared:
Common stock ($0.82/share)			( 206	)		( 206	)			( 206	)
Issuances of common stock		22				22				22
Repurchases of common stock		( 1	)			( 1	)			( 1	)
Noncontrolling interest activities:
Equity contributions								1		1
Distributions								( 89	)	( 89	)
Balance at September 30, 2017	$ —	$ 3,088	$ 10,855	$ ( 678	)	$ 13,265		$ 2,237		$ 15,502
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Dollars in millions)
	Preferred stock	Common stock	Retained earnings	Accumulated other comprehensive income (loss)		Sempra Energy shareholders' equity	Non- controlling interests		Total equity
	(unaudited)
	Nine months ended September 30, 2018
Balance at December 31, 2017	$ —	$ 3,149	$ 10,147	$ ( 626	)	$ 12,670	$ 2,470		$ 15,140
Cumulative-effect adjustments from
changes in accounting principles			2	( 3	)	( 1	)		( 1	)
Net income			150			150	12		162
Other comprehensive income				17		17	15		32
Share-based compensation expense		50				50			50
Dividends declared:
Series A preferred stock ($4.60/share)			( 79	)		( 79	)		( 79	)
Series B preferred stock ($1.73/share)			( 10	)		( 10	)		( 10	)
Common stock ($2.69/share)			( 724	)		( 724	)		( 724	)
Preferred dividends of subsidiary			( 1	)		( 1	)		( 1	)
Issuance of series A preferred stock	1,693					1,693			1,693
Issuance of series B preferred stock	566					566			566
Issuances of common stock		2,302				2,302			2,302
Repurchases of common stock		( 20	)			( 20	)		( 20	)
Noncontrolling interest activities:
Equity contributions							3		3
Distributions							( 104	)	( 104	)
Purchases							( 1	)	( 1	)
Sales, net of offering costs		4				4	86		90
Increase from acquisition							13		13
Balance at September 30, 2018	$ 2,259	$ 5,485	$ 9,485	$ ( 612	)	$ 16,617	$ 2,494		$ 19,111
	Nine months ended September 30, 2017
Balance at December 31, 2016	$ —	$ 2,982	$ 10,717	$ ( 748	)	$ 12,951	$ 2,290		$ 15,241
Net income			758			758	44		802
Other comprehensive income				70		70	16		86
Share-based compensation expense		44				44			44
Dividends declared:
Common stock ($2.47/share)			( 619	)		( 619	)		( 619	)
Preferred dividends of subsidiary			( 1	)		( 1	)		( 1	)
Issuances of common stock		77				77			77
Repurchases of common stock		( 15	)			( 15	)		( 15	)
Noncontrolling interest activities:
Equity contributions							2		2
Distributions							( 115	)	( 115	)
Balance at September 30, 2017	$ —	$ 3,088	$ 10,855	$ ( 678	)	$ 13,265	$ 2,237		$ 15,502
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017 (1)		2018		2017 (1)
	(unaudited)
Operating revenues
Electric	$ 1,192		$ 1,131		$ 3,014		$ 2,952
Natural gas	107		105		391		399
Total operating revenues	1,299		1,236		3,405		3,351
Operating expenses
Cost of electric fuel and purchased power	448		417		1,045		994
Cost of natural gas	30		29		110		132
Operation and maintenance	262		253		761		725
Depreciation and amortization	174		170		509		499
Franchise fees and other taxes	85		74		217		197
Write-off of wildfire regulatory asset	—		351		—		351
Total operating expenses	999		1,294		2,642		2,898
Operating income (loss)	300		( 58	)	763		453
Other income, net	24		20		77		61
Interest income	1		—		3		—
Interest expense	( 56	)	( 53	)	( 161	)	( 151	)
Income (loss) before income taxes	269		( 91	)	682		363
Income tax (expense) benefit	( 53	)	72		( 151	)	( 72	)
Net income (loss)	216		( 19	)	531		291
Earnings attributable to noncontrolling interest	( 11	)	( 9	)	( 10	)	( 15	)
Earnings (losses) attributable to common shares	$ 205		$ ( 28	)	$ 521		$ 276

(1) As adjusted for the retrospective adoption of ASU 2017-07, which we discuss in Note 2.

See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	SDG&E shareholder’s equity
	Pretax amount		Income tax (expense) benefit		Net-of-tax amount		Noncontrolling interest (after-tax)	Total
	(unaudited)
	Three months ended September 30, 2018 and 2017
2018:
Net income	$ 258		$ ( 53	)	$ 205		$ 11	$ 216
Other comprehensive income (loss):
Financial instruments	—		—		—		2	2
Pension and other postretirement benefits	( 8	)	2		( 6	)	—	( 6	)
Total other comprehensive (loss) income	( 8	)	2		( 6	)	2	( 4	)
Comprehensive income	$ 250		$ ( 51	)	$ 199		$ 13	$ 212
2017:
Net (loss) income	$ ( 100	)	$ 72		$ ( 28	)	$ 9	$ ( 19	)
Other comprehensive income (loss):
Financial instruments	—		—		—		3	3
Pension and other postretirement benefits	1		—		1		—	1
Total other comprehensive income	1		—		1		3	4
Comprehensive (loss) income	$ ( 99	)	$ 72		$ ( 27	)	$ 12	$ ( 15	)

	Nine months ended September 30, 2018 and 2017
2018:
Net income	$ 672		$ ( 151	)	$ 521		$ 10	$ 531
Other comprehensive income (loss):
Financial instruments	—		—		—		7	7
Pension and other postretirement benefits	( 8	)	2		( 6	)	—	( 6	)
Total other comprehensive (loss) income	( 8	)	2		( 6	)	7	1
Comprehensive income	$ 664		$ ( 149	)	$ 515		$ 17	$ 532
2017:
Net income	$ 348		$ ( 72	)	$ 276		$ 15	$ 291
Other comprehensive income (loss):
Financial instruments	—		—		—		7	7
Pension and other postretirement benefits	1		—		1		—	1
Total other comprehensive income	1		—		1		7	8
Comprehensive income	$ 349		$ ( 72	)	$ 277		$ 22	$ 299

See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	September 30, 2018		December 31, 2017 (1)
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$ 27		$ 12
Restricted cash	17		6
Accounts receivable – trade, net	470		362
Accounts receivable – other, net	133		79
Due from unconsolidated affiliates	1		—
Inventories	103		105
Prepaid expenses	97		58
Regulatory assets	77		316
Fixed-price contracts and other derivatives	34		42
Greenhouse gas allowances	119		116
Other	35		4
Total current assets	1,113		1,100
Other assets:
Restricted cash	—		11
Regulatory assets	399		451
Nuclear decommissioning trusts	1,042		1,033
Greenhouse gas allowances	153		83
Sundry	281		328
Total other assets	1,875		1,906
Property, plant and equipment:
Property, plant and equipment	20,749		19,787
Less accumulated depreciation and amortization	( 5,225	)	( 4,949	)
Property, plant and equipment, net ($302 and $321 at September 30, 2018 and December 31, 2017, respectively, related to VIE)	15,524		14,838
Total assets	$ 18,512		$ 17,844

(1) Derived from audited financial statements.

See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	September 30, 2018		December 31, 2017 (1)
	(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$ 48		$ 253
Accounts payable	413		501
Due to unconsolidated affiliates	303		40
Interest payable	58		41
Accrued compensation and benefits	91		122
Accrued franchise fees	58		59
Current portion of long-term debt ($287 and $10 at September 30, 2018 and December 31, 2017, respectively, related to VIE)	336		220
Asset retirement obligations	92		77
Regulatory liabilities	73		18
Fixed-price contracts and other derivatives	46		60
Customer deposits	69		69
Greenhouse gas obligations	119		116
Other	78		46
Total current liabilities	1,784		1,622
Long-term debt ($284 at December 31, 2017 related to VIE)	5,404		5,335
Deferred credits and other liabilities:
Customer advances for construction	47		57
Pension and other postretirement benefit plan obligations, net of plan assets	172		182
Deferred income taxes	1,632		1,530
Deferred investment tax credits	16		18
Regulatory liabilities	2,319		2,225
Asset retirement obligations	774		762
Fixed-price contracts and other derivatives	107		153
Greenhouse gas obligations	29		—
Deferred credits and other	328		334
Total deferred credits and other liabilities	5,424		5,261
Commitments and contingencies (Note 11)
Equity:
Preferred stock (45 million shares authorized; none issued)	—		—
Common stock (255 million shares authorized; 117 million shares outstanding; no par value)	1,338		1,338
Retained earnings	4,539		4,268
Accumulated other comprehensive income (loss)	( 14	)	( 8	)
Total SDG&E shareholder’s equity	5,863		5,598
Noncontrolling interest	37		28
Total equity	5,900		5,626
Total liabilities and equity	$ 18,512		$ 17,844

(1) Derived from audited financial statements.

See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Nine months ended September 30,
	2018		2017 (1)
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 531		$ 291
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	509		499
Deferred income taxes and investment tax credits	88		( 5	)
Write-off of wildfire regulatory asset	—		351
Fixed-price contracts and other derivatives	( 1	)	( 1	)
Other	( 30	)	( 31	)
Net change in other working capital components	150		78
Changes in other noncurrent assets and liabilities, net	( 16	)	( 10	)
Net cash provided by operating activities	1,231		1,172
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	( 1,194	)	( 1,122	)
Purchases of nuclear decommissioning trust assets	( 703	)	( 1,082	)
Proceeds from sales of nuclear decommissioning trust assets	703		1,082
Decrease in loans to affiliate, net	—		31
Other	—		6
Net cash used in investing activities	( 1,194	)	( 1,085	)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	—		( 450	)
Issuances of debt (maturities greater than 90 days)	398		398
Payments on debt (maturities greater than 90 days)	( 204	)	( 183	)
(Decrease) increase in short-term debt, net	( 205	)	185
Capital distributions made by VIE, net	( 8	)	( 20	)
Debt issuance costs	( 3	)	( 4	)
Net cash used in financing activities	( 22	)	( 74	)
Increase in cash, cash equivalents and restricted cash	15		13
Cash, cash equivalents and restricted cash, January 1	29		20
Cash, cash equivalents and restricted cash, September 30	$ 44		$ 33
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$ 139		$ 134
Income tax payments, net	79		13
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued capital expenditures	$ 113		$ 135
Increase in capital lease obligations for investment in property, plant and equipment	—		500
Common dividends declared but not paid	250		—

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

See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Dollars in millions)
	Common stock	Retained earnings	Accumulated other comprehensive income (loss)		SDG&E shareholder's equity		Noncontrolling interest		Total equity
	(unaudited)
	Three months ended September 30, 2018
Balance at June 30, 2018	$ 1,338	$ 4,584	$ ( 8	)	$ 5,914		$ 29		$ 5,943
Net income		205			205		11		216
Other comprehensive (loss) income			( 6	)	( 6	)	2		( 4	)
Common stock dividends declared ($2.14/share)		( 250	)		( 250	)			( 250	)
Noncontrolling interest activities:
Equity contributions							1		1
Distributions							( 6	)	( 6	)
Balance at September 30, 2018	$ 1,338	$ 4,539	$ ( 14	)	$ 5,863		$ 37		$ 5,900
	Three months ended September 30, 2017
Balance at June 30, 2017	$ 1,338	$ 4,440	$ ( 8	)	$ 5,770		$ 34		$ 5,804
Net (loss) income		( 28	)		( 28	)	9		( 19	)
Other comprehensive income			1		1		3		4
Common stock dividends declared ($2.36/share)		( 275	)		( 275	)			( 275	)
Distributions to noncontrolling interest							( 11	)	( 11	)
Balance at September 30, 2017	$ 1,338	$ 4,137	$ ( 7	)	$ 5,468		$ 35		$ 5,503
	Nine months ended September 30, 2018
Balance at December 31, 2017	$ 1,338	$ 4,268	$ ( 8	)	$ 5,598		$ 28		$ 5,626
Net income		521			521		10		531
Other comprehensive (loss) income			( 6	)	( 6	)	7		1
Common stock dividends declared ($2.14/share)		( 250	)		( 250	)			( 250	)
Noncontrolling interest activities:
Equity contributions							2		2
Distributions							( 10	)	( 10	)
Balance at September 30, 2018	$ 1,338	$ 4,539	$ ( 14	)	$ 5,863		$ 37		$ 5,900
	Nine months ended September 30, 2017
Balance at December 31, 2016	$ 1,338	$ 4,311	$ ( 8	)	$ 5,641		$ 37		$ 5,678
Net income		276			276		15		291
Other comprehensive income			1		1		7		8
Common stock dividends declared ($3.86/share)		( 450	)		( 450	)			( 450	)
Noncontrolling interest activities:
Equity contributions							1		1
Distributions							( 25	)	( 25	)
Balance at September 30, 2017	$ 1,338	$ 4,137	$ ( 7	)	$ 5,468		$ 35		$ 5,503

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017 (1)		2018		2017 (1)
	(unaudited)
Operating revenues	$ 802		$ 684		$ 2,700		$ 2,695
Operating expenses
Cost of natural gas	224		153		663		740
Operation and maintenance	394		360		1,160		1,067
Depreciation and amortization	141		132		414		384
Franchise fees and other taxes	38		34		111		107
Total operating expenses	797		679		2,348		2,298
Operating income	5		5		352		397
Other income, net	3		13		49		51
Interest income	—		1		1		1
Interest expense	( 29	)	( 26	)	( 82	)	( 77	)
(Loss) income before income taxes	( 21	)	( 7	)	320		372
Income tax benefit (expense)	7		14		( 75	)	( 103	)
Net (loss) income	( 14	)	7		245		269
Preferred dividend requirements	—		—		( 1	)	( 1	)
(Losses) earnings attributable to common shares	$ ( 14	)	$ 7		$ 244		$ 268

(1) As adjusted for the retrospective adoption of ASU 2017-07, which we discuss in Note 2.

See Notes to Condensed Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Pretax amount		Income tax benefit (expense)	Net-of-tax amount
	(unaudited)
	Three months ended September 30, 2018 and 2017
2018:
Net loss/Comprehensive loss	$ ( 21	)	$ 7	$ ( 14	)
2017:
Net (loss) income/Comprehensive (loss) income	$ ( 7	)	$ 14	$ 7

	Nine months ended September 30, 2018 and 2017
2018:
Net income	$ 320	$ ( 75	)	$ 245
Other comprehensive income (loss):
Pension and other postretirement benefits	1	—		1
Total other comprehensive income	1	—		1
Comprehensive income	$ 321	$ ( 75	)	$ 246
2017:
Net income	$ 372	$ ( 103	)	$ 269
Other comprehensive income (loss):
Pension and other postretirement benefits	1	—		1
Total other comprehensive income	1	—		1
Comprehensive income	$ 373	$ ( 103	)	$ 270

See Notes to Condensed Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED BALANCE SHEETS
(Dollars in millions)
	September 30, 2018		December 31, 2017 (1)
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$ 4		$ 8
Accounts receivable – trade, net	342		517
Accounts receivable – other, net	106		90
Due from unconsolidated affiliates	49		4
Income taxes receivable	4		10
Inventories	156		124
Regulatory assets	12		9
Greenhouse gas allowances	178		179
Other	47		38
Total current assets	898		979
Other assets:
Regulatory assets	984		983
Insurance receivable for Aliso Canyon costs	474		418
Greenhouse gas allowances	108		9
Sundry	348		364
Total other assets	1,914		1,774
Property, plant and equipment:
Property, plant and equipment	17,732		16,772
Less accumulated depreciation and amortization	( 5,597	)	( 5,366	)
Property, plant and equipment, net	12,135		11,406
Total assets	$ 14,947		$ 14,159

(1) Derived from audited financial statements.

See Notes to Condensed Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	September 30, 2018		December 31, 2017 (1)
	(unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term debt	$ —		$ 116
Accounts payable – trade	453		502
Accounts payable – other	93		93
Due to unconsolidated affiliates	51		35
Accrued compensation and benefits	137		151
Regulatory liabilities	211		91
Current portion of long-term debt	3		501
Customer deposits	101		89
Reserve for Aliso Canyon costs	161		84
Greenhouse gas obligations	178		179
Other	274		205
Total current liabilities	1,662		2,046
Long-term debt	3,427		2,485
Deferred credits and other liabilities:
Customer advances for construction	99		92
Pension obligation, net of plan assets	663		789
Deferred income taxes	1,121		995
Deferred investment tax credits	9		10
Regulatory liabilities	1,655		1,697
Asset retirement obligations	1,941		1,885
Greenhouse gas obligations	58		—
Deferred credits and other	210		253
Total deferred credits and other liabilities	5,756		5,721
Commitments and contingencies (Note 11)
Shareholders’ equity:
Preferred stock (11 million shares authorized; 1 million shares outstanding)	22		22
Common stock (100 million shares authorized; 91 million shares outstanding;
no par value)	866		866
Retained earnings	3,234		3,040
Accumulated other comprehensive income (loss)	( 20	)	( 21	)
Total shareholders’ equity	4,102		3,907
Total liabilities and shareholders’ equity	$ 14,947		$ 14,159

(1) Derived from audited financial statements.

See Notes to Condensed Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Nine months ended September 30,
	2018		2017
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 245		$ 269
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	414		384
Deferred income taxes and investment tax credits	70		86
Other	( 4	)	( 22	)
Net change in other working capital components	391		359
Insurance receivable for Aliso Canyon costs	( 56	)	64
Changes in other noncurrent assets and liabilities, net	( 178	)	( 74	)
Net cash provided by operating activities	882		1,066
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	( 1,127	)	( 1,033	)
Increase in loans to affiliate, net	( 88	)	—
Other	6		—
Net cash used in investing activities	( 1,209	)	( 1,033	)
CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends paid	( 1	)	( 1	)
Issuances of long-term debt	949		—
Payments on long-term debt	( 500	)	—
Decrease in short-term debt, net	( 116	)	( 36	)
Debt issuance costs	( 9	)	—
Net cash provided by (used in) financing activities	323		( 37	)
Decrease in cash and cash equivalents	( 4	)	( 4	)
Cash and cash equivalents, January 1	8		12
Cash and cash equivalents, September 30	$ 4		$ 8
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$ 71		$ 65
Income tax (refunds) payments, net	( 1	)	22
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued capital expenditures	$ 178		$ 148
Increase in capital lease obligations for investment in property, plant and equipment	7		1
Common dividends declared but not paid	50		—

See Notes to Condensed Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Dollars in millions)
	Preferred stock	Common stock	Retained earnings	Accumulated other comprehensive income (loss)		Total shareholders’ equity
	(unaudited)
	Three months ended September 30, 2018
Balance at June 30, 2018	$ 22	$ 866	$ 3,298	$ ( 20	)	$ 4,166
Net loss			( 14	)		( 14	)
Dividends declared:
Preferred stock ($0.38/share)			—			—
Common stock ($0.55/share)			( 50	)		( 50	)
Balance at September 30, 2018	$ 22	$ 866	$ 3,234	$ ( 20	)	$ 4,102
	Three months ended September 30, 2017
Balance at June 30, 2017	$ 22	$ 866	$ 2,905	$ ( 21	)	$ 3,772
Net income			7			7
Preferred stock dividends declared ($0.38/share)			—			—
Balance at September 30, 2017	$ 22	$ 866	$ 2,912	$ ( 21	)	$ 3,779
	Nine months ended September 30, 2018
Balance at December 31, 2017	$ 22	$ 866	$ 3,040	$ ( 21	)	$ 3,907
Net income			245			245
Other comprehensive income				1		1
Dividends declared:
Preferred stock ($1.13/share)			( 1	)		( 1	)
Common stock ($0.55/share)			( 50	)		( 50	)
Balance at September 30, 2018	$ 22	$ 866	$ 3,234	$ ( 20	)	$ 4,102
	Nine months ended September 30, 2017
Balance at December 31, 2016	$ 22	$ 866	$ 2,644	$ ( 22	)	$ 3,510
Net income			269			269
Other comprehensive income				1		1
Preferred stock dividends declared ($1.13/share)			( 1	)		( 1	)
Balance at September 30, 2017	$ 22	$ 866	$ 2,912	$ ( 21	)	$ 3,779

SEMPRA ENERGY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. GENERAL INFORMATION AND OTHER FINANCIAL DATA

PRINCIPLES OF CONSOLIDATION

Sempra Energy

Sempra Energy’s Condensed Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 energy-services holding company, and its consolidated subsidiaries and VIEs. Sempra Global is the holding company for most of our subsidiaries that are not subject to California or Texas utility regulation. Sempra Energy’s subsidiaries are managed within seven separate reportable segments, which we discuss in Note 12. All references in these Notes to our reportable segments are not intended to refer to any legal entity with the same or similar name.

SDG&E

SDG&E’s Condensed Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E is the primary beneficiary, as we discuss below in “Variable Interest Entities.” SDG&E’s common stock is wholly owned by Enova Corporation, which is a wholly owned subsidiary of Sempra Energy.

SoCalGas

SoCalGas’ common stock is wholly owned by Pacific Enterprises, which is a wholly owned subsidiary of Sempra Energy.

In this report, we refer to SDG&E and SoCalGas collectively as the California Utilities.

BASIS OF PRESENTATION

This is a combined report of Sempra Energy, SDG&E and SoCalGas. We provide separate information for SDG&E and SoCalGas as required. References in this report to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, unless otherwise indicated by the context. We have eliminated intercompany accounts and transactions within the consolidated financial statements of each reporting entity.

Throughout this report, we refer to the following as Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements when discussed together or collectively:

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

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

▪ the Condensed Financial Statements and related Notes of SoCalGas.

We have prepared the Condensed Consolidated Financial Statements in conformity with U.S. GAAP and in accordance with the interim-period-reporting requirements of Form 10-Q. Results of operations for interim periods are not necessarily indicative of results for the entire year. We evaluated events and transactions that occurred after September 30, 2018 through the date the financial statements were issued and, in the opinion of management, the accompanying statements reflect all adjustments necessary for a fair presentation. These adjustments are only of a normal, recurring nature.

All December 31, 2017 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2017 Consolidated Financial Statements in the Annual Report. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to the interim-period-reporting provisions of U.S. GAAP and the SEC.

We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report and the impact of the adoption of new accounting standards on those policies in Note 2 below. We follow the same accounting policies for interim reporting purposes.

You should read the information in this Quarterly Report in conjunction with the Annual Report.

Reclassification on the Condensed Consolidated Statement of Operations

We have made a reclassification on the Condensed Consolidated Statement of Operations for the three months and nine months ended September 30, 2017 to conform to current year presentation. Line item captions for equity earnings (losses) before income tax and net of income tax have been combined into one line and presented after income tax expense (benefit). This reclassification is intended to treat the presentation of earnings from all equity method investees consistently and simplify the presentation on the statement of operations, while continuing to provide additional detail in the notes to the financial statements. We discuss our equity method investments further in Note 6. The following table summarizes the financial statement line items that were affected by this reclassification:

SEMPRA ENERGY – RECLASSIFICATION
(Dollars in millions)
	Three months ended September 30, 2017		Nine months ended September 30, 2017
	As previously presented	As currently presented	As previously presented		As currently presented
Condensed Consolidated Statement of Operations:
Equity earnings, before income tax	$ 10	$ —	$ 31		$ —
Income before income taxes and equity earnings (losses)
of certain unconsolidated subsidiaries	15	—	1,185		—
Income before income taxes and equity earnings of
unconsolidated subsidiaries	—	5	—		1,154
Equity earnings (losses), net of income tax	3	—	( 5	)	—
Equity earnings	—	13	—		26

Regulated Operations

The California Utilities and Sempra Mexico’s natural gas distribution utility, Ecogas, prepare their financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations. We discuss the effects of regulation in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report and revenue recognition at our utilities in Note 3 below.

Our Sempra Texas Utility segment is comprised of our equity method investment in Oncor Holdings, which owns 80.25 percent of Oncor, as we discuss in Notes 5 and 6. Oncor is a regulated electric transmission and distribution utility in the state of Texas. Oncor’s rates are regulated by the PUCT and certain cities and are subject to regulatory rate-setting processes and annual earnings oversight. Oncor prepares its financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations.

Sempra South American Utilities has controlling interests in two electric distribution utilities in South America, Chilquinta Energía in Chile and Luz del Sur in Peru. Revenues are based on tariffs that are set by government agencies in their respective countries based on an efficient model distribution company defined by those agencies. Because the tariffs are based on a model and are intended to cover the costs of the model company, but are not based on the costs of the specific utility and may not result in full cost recovery, these utilities do not meet the requirements necessary for, and therefore do not apply, regulatory accounting treatment under U.S. GAAP.

Our Sempra Mexico segment includes the operating companies of our subsidiary, IEnova. Certain business activities at IEnova are regulated by the CRE and meet the regulatory accounting requirements of U.S. GAAP. Pipeline projects under construction at Sempra Mexico that meet the regulatory accounting requirements of U.S. GAAP record the impact of AFUDC related to equity. We discuss AFUDC below and in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

RESTRICTED CASH

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported on the Condensed Consolidated Balance Sheets to the sum of such amounts reported on the Condensed Consolidated Statements of Cash Flows. We provide information about the nature of restricted cash in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

RECONCILIATION OF CASH, CASH EQUIVALENTS AND RESTRICTED CASH
(Dollars in millions)
	September 30,	December 31,
	2018	2017
Sempra Energy Consolidated:
Cash and cash equivalents	$ 212	$ 288
Restricted cash, current	73	62
Restricted cash, noncurrent	3	14
Total cash, cash equivalents and restricted cash on the Condensed Consolidated Statements of Cash Flows	$ 288	$ 364
SDG&E:
Cash and cash equivalents	$ 27	$ 12
Restricted cash, current	17	6
Restricted cash, noncurrent	—	11
Total cash, cash equivalents and restricted cash on the Condensed Consolidated Statements of Cash Flows	$ 44	$ 29

INVENTORIES

The following table presents the components of inventories by segment.

INVENTORY BALANCES
(Dollars in millions)
	Natural gas		LNG		Materials and supplies		Total
	September 30, 2018	December 31, 2017	September 30, 2018	December 31, 2017	September 30, 2018	December 31, 2017	September 30, 2018	December 31, 2017
SDG&E	$ 1	$ 4	$ —	$ —	$ 102	$ 101	$ 103	$ 105
SoCalGas	116	75	—	—	40	49	156	124
Sempra South American Utilities	—	—	—	—	41	30	41	30
Sempra Mexico	—	—	6	7	15	2	21	9
Sempra Renewables	—	—	—	—	—	5	—	5
Sempra LNG & Midstream	24	30	—	4	—	—	24	34
Sempra Energy Consolidated	$ 141	$ 109	$ 6	$ 11	$ 198	$ 187	$ 345	$ 307

At September 30, 2018 , $ 5 million of inventories at Sempra Renewables was classified as Assets Held for Sale on the Sempra Energy Condensed Consolidated Balance Sheet, as we discuss in Note 5.

GOODWILL

We discuss goodwill in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. The decrease in goodwill from $ 2,397 million at December 31, 2017 to $ 2,363 million at September 30, 2018 was due to foreign currency translation at Sempra South American Utilities. We recorded the offset of this fluctuation in OCI.

OTHER INTANGIBLE ASSETS

The following table provides the detail of Other Intangible Assets included on the Sempra Energy Condensed Consolidated Balance Sheets.

OTHER INTANGIBLE ASSETS
(Dollars in millions)
	Amortization period (years)	September 30, 2018		December 31, 2017
Development rights	50	$ —		$ 322
Renewable energy transmission and consumption permit	19	154		154
Storage rights	46	—		138
O&M agreement	23	66		66
Other	10 years to indefinite	32		18
		252		698
Less accumulated amortization:
Development rights		—		( 60	)
Renewable energy transmission and consumption permit		( 14	)	( 8	)
Storage rights		—		( 28	)
O&M agreement		( 2	)	—
Other		( 7	)	( 6	)
		( 23	)	( 102	)
		$ 229		$ 596

In June 2018, we recognized an impairment of $ 369 million for the net carrying value of Other Intangible Assets at Sempra LNG & Midstream, representing development and storage rights related to the natural gas storage facilities of Mississippi Hub and Bay Gas. This impairment is included in Sempra LNG & Midstream’s total impairment of $ 1.3 billion , which is included in Impairment Losses on Sempra Energy’s Condensed Consolidated Statements of Operations in the nine months ended September 30, 2018 , as we discuss in Notes 5 and 9.

In the nine months ended September 30, 2018, Other Intangible Assets increased due to Sempra Mexico’s acquisition of self-supply permits for development projects. These self-supply permits allow generators to compete directly with CFE’s retail tariffs and, thus, have access to PPAs with a competitive pricing position. The useful life of a self-supply permit is based on the life of the interconnection agreement with the CFE. Amortization of self-supply permits begins when the project has commenced planned operations.

Intangible assets subject to amortization are amortized over their estimated useful lives. Amortization expense for such intangible assets was $ 3 million and $ 5 million for the three months ended September 30, 2018 and 2017 , respectively, and $ 13 million for both the nine months ended September 30, 2018 and 2017. We estimate the amortization for the next five years to be $ 12 million a year. We provide additional information about Other Intangible Assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

CAPITALIZED FINANCING COSTS

Capitalized financing costs include capitalized interest costs and AFUDC related to both debt and equity financing of construction projects. We capitalize interest costs incurred to finance capital projects and interest on equity method investments that have not commenced planned principal operations.

The table below summarizes capitalized interest and AFUDC.

CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Three months ended September 30,		Nine months ended September 30,
	2018	2017	2018	2017
Sempra Energy Consolidated	$ 49	$ 54	$ 157	$ 198
SDG&E	20	21	67	62
SoCalGas	10	15	39	45

VARIABLE INTEREST ENTITIES

We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based upon qualitative and quantitative analyses, which assess:

▪ the purpose and design of the VIE;

▪ the nature of the VIE’s risks and the risks we absorb;

▪ the power to direct activities that most significantly impact the economic performance of the VIE; and

▪ the obligation to absorb losses or the right to receive benefits that could be significant to the VIE.

We will continue to evaluate our VIEs for any changes that may impact our determination of the primary beneficiary.

SDG&E

SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various PPAs that include variable interests. SDG&E evaluates the respective entities to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and thereby Sempra Energy, is the primary beneficiary.

Tolling Agreements

SDG&E has agreements under which it purchases power generated by facilities for which it supplies all of the natural gas to fuel the power plant (i.e., tolling agreements). SDG&E’s obligation to absorb natural gas costs may be a significant variable interest. In addition, SDG&E has the power to direct the dispatch of electricity generated by these facilities. Based on our analysis, the ability to direct the dispatch of electricity may have the most significant impact on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. SDG&E determines if it is the primary beneficiary in these cases based on a qualitative approach in which we consider the operational characteristics of the facility, including its expected power generation output relative to its capacity to generate and the financial structure of the entity, among other factors. If we determine that SDG&E is the primary beneficiary, SDG&E and Sempra Energy consolidate the entity that owns the facility as a VIE.

Otay Mesa VIE

SDG&E has a tolling agreement to purchase power generated at OMEC, a 605 -MW generating facility. A related agreement provided SDG&E with the option to purchase OMEC at a predetermined price (referred to as the call option). SDG&E’s call option has since expired unexercised. Under the terms of the agreement, the counterparty can require SDG&E to purchase the power plant for $ 280 million , subject to adjustments, on or before October 3, 2019 (referred to as the put option), or upon earlier termination of the PPA.

The facility owner, OMEC LLC, is a VIE, which we refer to as Otay Mesa VIE, of which SDG&E is the primary beneficiary. SDG&E has no OMEC LLC voting rights, holds no equity in OMEC LLC and does not operate OMEC. In addition to the risks absorbed under the tolling agreement, SDG&E absorbs separately through the put option a significant portion of the risk that the value of Otay Mesa VIE could decline. Accordingly, SDG&E and Sempra Energy consolidate Otay Mesa VIE. Otay Mesa VIE’s equity of $ 37 million at September 30, 2018 and $ 28 million at December 31, 2017 is included on the Condensed Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.

On October 24, 2018, SDG&E and OMEC LLC signed a resource adequacy capacity agreement for a term that would commence at the expiration of the current tolling agreement in October 2019 and end on August 31, 2024. The capacity agreement is contingent upon receiving approval from OMEC LLC’s lenders by December 31, 2018, and receiving approval from the CPUC by March 15, 2019. If the resource adequacy capacity agreement is approved, OMEC LLC will waive its right to exercise the put option and, as a result, SDG&E would no longer consolidate Otay Mesa VIE. SDG&E filed for CPUC approval of the resource adequacy capacity agreement in October 2018.

OMEC LLC has a loan outstanding of $ 287 million at September 30, 2018 , the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is collateralized by OMEC’s assets. SDG&E is not a party to the loan agreement and does not have any additional implicit or explicit financial responsibility to OMEC LLC, nor would SDG&E be required to assume OMEC’s loan under the call or put option purchase scenarios. The loan fully matures in April 2019, prior to the expiration of the put option, and bears interest at rates varying with market rates. In addition, OMEC LLC has entered into

interest rate swap agreements to moderate its exposure to interest rate changes. We provide additional information concerning the interest rate swaps in Note 8.

The Condensed Consolidated Statements of Operations of Sempra Energy and SDG&E include the following amounts associated with Otay Mesa VIE. The amounts are net of eliminations of transactions between SDG&E and Otay Mesa VIE. The captions in the table below correspond to SDG&E’s Condensed Consolidated Statements of Operations.

AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
Operating expenses
Cost of electric fuel and purchased power	$ ( 28	)	$ ( 26	)	$ ( 60	)	$ ( 65	)
Operation and maintenance	3		4		11		13
Depreciation and amortization	8		7		23		21
Total operating expenses	( 17	)	( 15	)	( 26	)	( 31	)
Operating income	17		15		26		31
Interest expense	( 6	)	( 6	)	( 16	)	( 16	)
Income before income taxes/Net income	11		9		10		15
Earnings attributable to noncontrolling interest	( 11	)	( 9	)	( 10	)	( 15	)
Earnings attributable to common shares	$ —		$ —		$ —		$ —

SDG&E has determined that no contracts, other than the one relating to Otay Mesa VIE mentioned above, resulted in SDG&E being the primary beneficiary of a VIE at September 30, 2018 . In addition to the tolling agreements described above, other variable interests involve various elements of fuel and power costs, and other components of cash flows expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities that most significantly impact the economic performance of the other VIEs. In addition, SDG&E is not exposed to losses or gains as a result of these other VIEs, because all such variability would be recovered in rates. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects could be significant to the financial position and liquidity of SDG&E and Sempra Energy. We provide additional information about PPAs with power plant facilities that are VIEs of which SDG&E is not the primary beneficiary in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

We provide additional information regarding Otay Mesa VIE in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra Texas Utility

On March 9, 2018, we completed the acquisition of an indirect, 100 -percent interest in Oncor Holdings, a VIE that owns an 80.25 -percent interest in Oncor. Sempra Energy is not the primary beneficiary of the VIE because of the structural and operational ring-fencing measures in place that prevent us from having the power to direct the significant activities of Oncor Holdings. As a result, we do not consolidate Oncor Holdings and instead account for our ownership interest as an equity method investment. See Notes 5 and 6 for additional information about our equity method investment in Oncor Holdings and restrictions in our ability to influence its activities. Our current maximum exposure to loss from our interest in Oncor Holdings did not exceed the carrying value of our investment, which was $ 9,553 million at September 30, 2018 . Our maximum exposure will fluctuate over time, including as a result of our commitment to contribute $ 1,025 million in capital (excluding Sempra Energy’s share of approximately $ 40 million for a management agreement termination fee, as well as other customary transaction costs incurred by InfraREIT that will be borne by Oncor as part of the acquisition) to partially fund Oncor’s acquisition of interests in InfraREIT, which we discuss in Note 5.

Sempra Renewables

Certain of Sempra Renewables’ wind and solar power generation projects are held by limited liability companies whose members are Sempra Renewables and financial institutions. The financial institutions are noncontrolling tax equity investors to which earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. These entities are VIEs and Sempra Energy is the primary beneficiary, generally due to Sempra Energy’s power as the operator of the renewable energy projects to direct the activities that most significantly impact the economic performance of these VIEs. As the primary beneficiary of these tax equity limited liability companies, we consolidate them.

Sempra Energy’s Condensed Consolidated Balance Sheets include $ 1,412 million of property, plant and equipment, net, at December 31, 2017 and equity of $ 656 million and $ 631 million of Other Noncontrolling Interests at September 30, 2018 and December 31, 2017 , respectively, associated with these entities. At September 30, 2018, $ 1,414 million of property, plant and equipment, net, plus other assets and liabilities associated with these entities, are classified as held for sale, as we discuss in Note 5.

Sempra Energy’s Condensed Consolidated Statements of Operations include the following amounts associated with the tax equity limited liability companies, net of eliminations of transactions between Sempra Energy and these entities.

AMOUNTS ASSOCIATED WITH TAX EQUITY ARRANGEMENTS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
REVENUES
Energy-related businesses	$ 28		$ 17		$ 77		$ 48
EXPENSES
Operation and maintenance	( 5	)	( 5	)	( 13	)	( 14	)
Depreciation and amortization	( 13	)	( 8	)	( 36	)	( 24	)
Income before income taxes	10		4		28		10
Income tax expense	( 4	)	( 3	)	( 16	)	( 9	)
Net income	6		1		12		1
Losses attributable to noncontrolling interests (1)	9		6		50		16
Earnings attributable to common shares	$ 15		$ 7		$ 62		$ 17

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

We provide additional information regarding the tax equity limited liability companies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra LNG & Midstream

Sempra Energy’s equity method investment in Cameron LNG JV is considered to be a VIE principally due to contractual provisions that transfer certain risks to customers. Sempra Energy is not the primary beneficiary of the VIE because we do not have the power to direct the most significant activities of Cameron LNG JV. The carrying value of our investment in Cameron LNG JV, including amounts recognized in AOCI related to interest-rate cash flow hedges at Cameron LNG JV, was $ 1,252 million at September 30, 2018 and $ 997 million at December 31, 2017 . Our current maximum exposure to loss, which fluctuates over time, includes the carrying value of our investment and the guarantees that we discuss in Note 6 below and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Variable Interest Entities

Sempra Energy’s other businesses also enter into arrangements which could include variable interests. We evaluate these arrangements and applicable entities based on the qualitative and quantitative analyses described above. Certain of these entities are service or project companies that are VIEs. As the primary beneficiary of these companies, we consolidate them; however, their financial statements are not material to the financial statements of Sempra Energy. In all other cases, we have determined that these arrangements are not variable interests in a VIE and therefore are not subject to the U.S. GAAP requirements concerning the consolidation of VIEs.

ASSET RETIREMENT OBLIGATIONS

We discuss asset retirement obligations in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We summarize changes in asset retirement obligations in the following table.

CHANGES IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
	Sempra Energy
	Consolidated				SDG&E				SoCalGas
	2018		2017		2018		2017		2018		2017
Balance at January 1 (1)	$ 2,877		$ 2,553		$ 839		$ 830		$ 1,953		$ 1,659
Accretion expense	90		81		29		30		58		49
Liabilities incurred	7		22		—		17		—		—
Reclassifications (2)	( 60	)	—		—		—		—		—
Payments	( 34	)	( 44	)	( 31	)	( 43	)	( 2	)	( 1	)
Revisions	28		( 8	)	29		—		( 2	)	( 8	)
Balance at September 30 (1)	$ 2,908		$ 2,604		$ 866		$ 834		$ 2,007		$ 1,699

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

(2) In 2018, we reclassified $ 57 million at Sempra Renewables and $ 8 million at Sempra LNG & Midstream to Liabilities Held for Sale, and $ 5 million related to TdM from Liabilities Held for Sale, as we discuss in Note 5.

PENSION AND OTHER POSTRETIREMENT BENEFITS

Sale of Qualified Pension Plan Annuity Contracts

In March 2018, an insurance company purchased annuities for certain current annuitants in the SDG&E and SoCalGas qualified pension plans and assumed the obligation for payment of these annuities. At SDG&E in the first quarter of 2018 and at SoCalGas in the second quarter of 2018, the liability transferred for these annuities, plus the total year-to-date lump-sum payments, exceeded the settlement threshold, which triggered settlement accounting. This resulted in a reduction of the recorded pension liability and pension plan assets of $ 300 million at Sempra Energy Consolidated, including $ 108 million at SDG&E and $ 192 million at SoCalGas. This also resulted in settlement charges in net periodic benefit cost of $ 3 million and $ 42 million at Sempra Energy Consolidated, including $ 1 million and $ 17 million at SDG&E and $ 2 million and $ 25 million at SoCalGas in the three months and nine months ended September 30, 2018 , respectively. The settlement charges were recorded as regulatory assets on the Condensed Consolidated Balance Sheets.

Acquisition

On March 9, 2018, Sempra Energy completed the Merger, as we discuss in Note 5, and assumed other postretirement employee benefits obligations for health care and life insurance benefits, resulting in an increase of $ 21 million in the other postretirement benefit plan liability at Sempra Energy Consolidated.

Net Periodic Benefit Cost

The following three tables provide the components of net periodic benefit cost.

NET PERIODIC BENEFIT COST – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension benefits				Other postretirement benefits
	Three months ended September 30,
	2018		2017		2018		2017
Service cost	$ 29		$ 31		$ 4		$ 4
Interest cost	36		39		9		9
Expected return on assets	( 36	)	( 41	)	( 18	)	( 16	)
Amortization of:
Prior service cost	3		3		—		—
Actuarial loss (gain)	7		11		( 2	)	( 2	)
Settlements	9		8		—		—
Special termination benefits	—		—		5		16
Net periodic benefit cost	48		51		( 2	)	11
Regulatory adjustment	( 11	)	( 18	)	2		( 11	)
Total expense recognized	$ 37		$ 33		$ —		$ —
	Nine months ended September 30,
	2018		2017		2018		2017
Service cost	$ 95		$ 88		$ 15		$ 15
Interest cost	105		113		27		29
Expected return on assets	( 117	)	( 121	)	( 53	)	( 49	)
Amortization of:
Prior service cost	8		8		—		—
Actuarial loss (gain)	26		27		( 4	)	( 3	)
Settlements	48		8		—		—
Special termination benefits	—		—		5		16
Net periodic benefit cost	165		123		( 10	)	8
Regulatory adjustment	( 91	)	( 59	)	11		( 7	)
Total expense recognized	$ 74		$ 64		$ 1		$ 1

NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
	Pension benefits				Other postretirement benefits
	Three months ended September 30,
	2018		2017		2018		2017
Service cost	$ 7		$ 7		$ 1		$ 1
Interest cost	9		9		2		2
Expected return on assets	( 10	)	( 11	)	( 3	)	( 2	)
Amortization of:
Actuarial loss (gain)	—		3		( 1	)	—
Settlements	1		—		—		—
Special termination benefits	—		—		3		—
Net periodic benefit cost	7		8		2		1
Regulatory adjustment	( 7	)	( 7	)	( 2	)	( 1	)
Total expense recognized	$ —		$ 1		$ —		$ —
	Nine months ended September 30,
	2018		2017		2018		2017
Service cost	$ 23		$ 22		$ 3		$ 4
Interest cost	26		28		5		6
Expected return on assets	( 35	)	( 35	)	( 10	)	( 9	)
Amortization of:
Prior service cost	1		1		2		2
Actuarial loss (gain)	3		7		( 2	)	—
Settlements	17		—		—		—
Special termination benefits	—		—		3		—
Net periodic benefit cost	35		23		1		3
Regulatory adjustment	( 34	)	( 21	)	( 1	)	( 3	)
Total expense recognized	$ 1		$ 2		$ —		$ —

NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
	Pension benefits				Other postretirement benefits
	Three months ended September 30,
	2018		2017		2018		2017
Service cost	$ 19		$ 21		$ 3		$ 4
Interest cost	23		25		6		6
Expected return on assets	( 22	)	( 26	)	( 13	)	( 14	)
Amortization of:
Prior service cost (credit)	2		3		( 1	)	( 1	)
Actuarial loss (gain)	3		6		( 1	)	( 1	)
Settlements	2		—		—		—
Special termination benefits	—		—		2		16
Net periodic benefit cost	27		29		( 4	)	10
Regulatory adjustment	( 4	)	( 11	)	4		( 10	)
Total expense recognized	$ 23		$ 18		$ —		$ —
	Nine months ended September 30,
	2018		2017		2018		2017
Service cost	$ 62		$ 57		$ 11		$ 11
Interest cost	68		73		20		21
Expected return on assets	( 73	)	( 77	)	( 41	)	( 40	)
Amortization of:
Prior service cost (credit)	6		7		( 2	)	( 2	)
Actuarial loss (gain)	15		14		( 2	)	( 2	)
Settlements	25		—		—		—
Special termination benefits	—		—		2		16
Net periodic benefit cost	103		74		( 12	)	4
Regulatory adjustment	( 57	)	( 38	)	12		( 4	)
Total expense recognized	$ 46		$ 36		$ —		$ —

Benefit Plan Contributions

The following table shows our year-to-date contributions to pension and other postretirement benefit plans and the amounts we expect to contribute in 2018 .

BENEFIT PLAN CONTRIBUTIONS
(Dollars in millions)
	Sempra Energy Consolidated	SDG&E	SoCalGas
Contributions through September 30, 2018:
Pension plans	$ 76	$ 3	$ 46
Other postretirement benefit plans	2	—	1
Total expected contributions in 2018:
Pension plans	$ 192	$ 48	$ 105
Other postretirement benefit plans	6	1	2

RABBI TRUST

In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra Energy maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $ 443 million and $ 455 million at September 30, 2018 and December 31, 2017 , respectively.

EARNINGS PER COMMON SHARE

The following table provides EPS computations for the three months and nine months ended September 30, 2018 and 2017 . Basic EPS is calculated by dividing earnings attributable to common shares by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

EARNINGS PER COMMON SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
	Three months ended September 30,		Nine months ended September 30,
	2018	2017	2018	2017
Numerator:
Earnings attributable to common shares	$ 274	$ 57	$ 60	$ 757
Denominator:
Weighted-average common shares outstanding for basic EPS (1)	273,944	251,692	265,963	251,425
Dilutive effect of stock options, RSAs and RSUs (2)	854	1,672	736	1,562
Dilutive effect of common shares sold forward	1,109	—	945	—
Weighted-average common shares outstanding for diluted EPS	275,907	253,364	267,644	252,987
EPS:
Basic	$ 1.00	$ 0.23	$ 0.23	$ 3.01
Diluted	$ 0.99	$ 0.22	$ 0.22	$ 2.99

(1) Includes 645 and 612 average fully vested RSUs held in our Deferred Compensation Plan for the three months ended September 30, 2018 and 2017 , respectively, and 638 and 607 of such RSUs for the nine months ended September 30, 2018 and 2017 , respectively. These fully vested RSUs are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.

(2) Due to market fluctuations of both Sempra Energy common 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 of the Notes to Consolidated Financial Statements in the Annual Report, dilutive RSUs may vary widely from period-to-period.

The potentially dilutive impact from stock options, RSAs and RSUs is calculated under the treasury stock method. Under this method, proceeds based on the exercise price and unearned compensation are assumed to be used to repurchase shares on the open market at the average market price for the period, reducing the number of potential new shares to be issued and sometimes causing an antidilutive effect. The computation of diluted EPS for the three months ended September 30, 2018 and 2017 excludes 508 and 2,608 potentially dilutive shares, respectively, because to include them would be antidilutive for the period. The computation of diluted EPS for the nine months ended September 30, 2018 and 2017 excludes 1,552 and 2,608 such potentially dilutive shares, respectively. However, these shares could potentially dilute basic EPS in the future.

The potentially dilutive impact from the forward sale of our common stock pursuant to the forward sale agreements that we discuss below in “Shareholders’ Equity and Noncontrolling Interests – Sempra Energy Common Stock Offerings,” is reflected in our diluted EPS calculation using the treasury stock method. We anticipate there will be a dilutive effect on our EPS when the average market price of shares of our common stock is above the applicable adjusted forward sale price, subject to increase or decrease based on the overnight bank funding rate, less a spread, and subject to decrease by amounts related to expected dividends on shares of our common stock during the term of the forward sale agreements. The computation of diluted EPS for the three months and nine months ended September 30, 2018 excludes zero and 2,857,143 potentially dilutive shares, respectively, because to include them would be antidilutive for the period. Additionally, if we decide to physically settle or net share settle the forward sale agreements, delivery of our shares to the forward purchasers on any such physical settlement or net share settlement of the forward sale agreements would result in dilution to our EPS.

The potentially dilutive impact from mandatory convertible preferred stock that we issued in 2018 is calculated under the if-converted method. The computation of diluted EPS for the three months and nine months ended September 30, 2018 excludes 19,152,109 and 15,863,530 potentially dilutive shares, respectively, because to include them would be antidilutive for the period. However, these shares could potentially dilute basic EPS in the future. We discuss the 2018 issuances of our mandatory convertible preferred stock in “Shareholders’ Equity and Noncontrolling Interests – Sempra Energy Mandatory Convertible Preferred Stock Offerings” below.

Pursuant to our Sempra Energy share-based compensation plans, Sempra Energy’s Board of Directors granted 358,363 performance-based RSUs and 266,990 service-based RSUs in the nine months ended September 30, 2018 , primarily in January. In the nine months ended September 30, 2018 , IEnova granted 969,482 RSUs from the IEnova 2013 Long-Term Incentive Plan, under which awards are cash settled at vesting based on the price of IEnova common stock.

We discuss share-based compensation plans and related awards further in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report.

COMPREHENSIVE INCOME

The following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income, excluding amounts attributable to NCI.

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT (1)
(Dollars in millions)
	Foreign currency translation adjustments		Financial instruments		Pension and other postretirement benefits		Total accumulated other comprehensive income (loss)
	Three months ended September 30, 2018 and 2017
Sempra Energy Consolidated:
Balance as of June 30, 2018	$ ( 482	)	$ ( 40	)	$ ( 79	)	$ ( 601	)
OCI before reclassifications	( 16	)	19		( 18	)	( 15	)
Amounts reclassified from AOCI	—		( 4	)	8		4
Net OCI	( 16	)	15		( 10	)	( 11	)
Balance as of September 30, 2018	$ ( 498	)	$ ( 25	)	$ ( 89	)	$ ( 612	)
					.
Balance as of June 30, 2017	$ ( 478	)	$ ( 147	)	$ ( 93	)	$ ( 718	)
OCI before reclassifications	27		8		—		35
Amounts reclassified from AOCI	—		( 2	)	7		5
Net OCI	27		6		7		40
Balance as of September 30, 2017	$ ( 451	)	$ ( 141	)	$ ( 86	)	$ ( 678	)
SDG&E:
Balance as of June 30, 2018					$ ( 8	)	$ ( 8	)
OCI before reclassifications					( 6	)	( 6	)
Net OCI					( 6	)	( 6	)
Balance as of September 30, 2018					$ ( 14	)	$ ( 14	)
Balance as of June 30, 2017					$ ( 8	)	$ ( 8	)
Amounts reclassified from AOCI					1		1
Net OCI					1		1
Balance as of September 30, 2017					$ ( 7	)	$ ( 7	)
SoCalGas:
Balance as of June 30, 2018 and September 30, 2018			$ ( 13	)	$ ( 7	)	$ ( 20	)
Balance as of June 30, 2017 and September 30, 2017			$ ( 13	)	$ ( 8	)	$ ( 21	)

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

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT (1)
(Dollars in millions)
	Foreign currency translation adjustments		Financial instruments		Pension and other postretirement benefits		Total accumulated other comprehensive income (loss)
	Nine months ended September 30, 2018 and 2017
Sempra Energy Consolidated:
Balance as of December 31, 2017	$ ( 420	)	$ ( 122	)	$ ( 84	)	$ ( 626	)
Cumulative-effect adjustment from change in accounting principle (2)	—		( 3	)	—		( 3	)
OCI before reclassifications	( 78	)	104		( 17	)	9
Amounts reclassified from AOCI	—		( 4	)	12		8
Net OCI	( 78	)	100		( 5	)	17
Balance as of September 30, 2018	$ ( 498	)	$ ( 25	)	$ ( 89	)	$ ( 612	)
Balance as of December 31, 2016	$ ( 527	)	$ ( 125	)	$ ( 96	)	$ ( 748	)
OCI before reclassifications	76		( 20	)	—		56
Amounts reclassified from AOCI	—		4		10		14
Net OCI	76		( 16	)	10		70
Balance as of September 30, 2017	$ ( 451	)	$ ( 141	)	$ ( 86	)	$ ( 678	)
SDG&E:
Balance as of December 31, 2017					$ ( 8	)	$ ( 8	)
OCI before reclassifications					( 6	)	( 6	)
Net OCI					( 6	)	( 6	)
Balance as of September 30, 2018					$ ( 14	)	$ ( 14	)
Balance as of December 31, 2016					$ ( 8	)	$ ( 8	)
Amounts reclassified from AOCI					1		1
Net OCI					1		1
Balance as of September 30, 2017					$ ( 7	)	$ ( 7	)
SoCalGas:
Balance as of December 31, 2017			$ ( 13	)	$ ( 8	)	$ ( 21	)
Amounts reclassified from AOCI			—		1		1
Net OCI			—		1		1
Balance as of September 30, 2018			$ ( 13	)	$ ( 7	)	$ ( 20	)
Balance as of December 31, 2016			$ ( 13	)	$ ( 9	)	$ ( 22	)
Amounts reclassified from AOCI			—		1		1
Net OCI			—		1		1
Balance as of September 30, 2017			$ ( 13	)	$ ( 8	)	$ ( 21	)

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

(2) Represents impact from adoption of ASU 2017-12, which we discuss in Note 2.

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated other comprehensive income (loss) components	Amounts reclassified from accumulated other comprehensive income (loss)				Affected line item on Condensed Consolidated Statements of Operations
	Three months ended September 30,
	2018		2017
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments	$ ( 11	)	$ —		Other Income, Net
Interest rate and foreign exchange instruments	3		—		Equity Earnings
Foreign exchange instruments	—		( 2	)	Revenues: Energy-Related Businesses
Total before income tax	( 8	)	( 2	)
	4		1		Income Tax (Expense) Benefit
Net of income tax	( 4	)	( 1	)
	—		( 1	)	Earnings Attributable to Noncontrolling Interests
	$ ( 4	)	$ ( 2	)
Pension and other postretirement benefits:
Amortization of actuarial loss (1)	$ 9		$ 11		Other Income, Net
Amortization of prior service cost (1)	1		—		Other Income, Net
Total before income tax	10		11
	( 2	)	( 4	)	Income Tax (Expense) Benefit
Net of income tax	$ 8		$ 7
Total reclassifications for the period, net of tax	$ 4		$ 5
SDG&E:
Financial instruments:
Interest rate instruments (2)	$ 2		$ 3		Interest Expense
	( 2	)	( 3	)	Earnings Attributable to Noncontrolling Interest
	$ —		$ —
Pension and other postretirement benefits:
Amortization of actuarial loss (1)	$ —		$ 1		Other Income, Net
Total reclassifications for the period, net of tax	$ —		$ 1

(1) Amounts are included in the computation of net periodic benefit cost (see “Pension and Other Postretirement Benefits” above).

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

For the three months ended September 30, 2018 and 2017, reclassifications out of AOCI to net income were negligible for SoCalGas.

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated other comprehensive income (loss) components	Amounts reclassified from accumulated other comprehensive income (loss)				Affected line item on Condensed Consolidated Statements of Operations
	Nine months ended September 30,
	2018		2017
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments (1)	$ ( 1	)	$ ( 4	)	Interest Expense
	( 11	)	—		Other Income, Net
Interest rate and foreign exchange instruments	8		9		Equity Earnings
Foreign exchange instruments	( 1	)	( 1	)	Revenues: Energy-Related Businesses
Commodity contracts not subject to rate recovery	—		9		Revenues: Energy-Related Businesses
Total before income tax	( 5	)	13
	3		( 4	)	Income Tax (Expense) Benefit
Net of income tax	( 2	)	9
	( 2	)	( 5	)	Earnings Attributable to Noncontrolling Interests
	$ ( 4	)	$ 4
Pension and other postretirement benefits:
Amortization of actuarial loss (2)	$ 15		$ 16		Other Income, Net
Amortization of prior service cost (2)	1		—		Other Income, Net
Total before income tax	16		16
	( 4	)	( 6	)	Income Tax (Expense) Benefit
Net of income tax	$ 12		$ 10
Total reclassifications for the period, net of tax	$ 8		$ 14
SDG&E:
Financial instruments:
Interest rate instruments (1)	$ 6		$ 9		Interest Expense
	( 6	)	( 9	)	Earnings Attributable to Noncontrolling Interest
	$ —		$ —
Pension and other postretirement benefits:
Amortization of actuarial loss (2)	$ —		$ 1		Other Income, Net
Total reclassifications for the period, net of tax	$ —		$ 1
SoCalGas:
Pension and other postretirement benefits:
Amortization of actuarial loss (2)	$ 1		$ 1		Other Income, Net
Total reclassifications for the period, net of tax	$ 1		$ 1

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

(2) Amounts are included in the computation of net periodic benefit cost (see “Pension and Other Postretirement Benefits” above).

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS

Sempra Energy Mandatory Convertible Preferred Stock Offerings

6 % Mandatory Convertible Preferred Stock, Series A

On January 9, 2018, we issued 17,250,000 shares of our series A preferred stock in a registered public offering at $ 100.00 per share (or $ 98.20 per share after deducting underwriting discounts), including 2,250,000 shares purchased by the underwriters directly from us as a result of fully exercising their option to purchase such shares from us solely to cover overallotments. Each share of series A preferred stock has a liquidation value of $ 100.00 . We used the net proceeds of approximately $ 1.69 billion (net of underwriting discounts and equity issuance costs of $ 32 million ) to fund a portion of the Merger Consideration, as we discuss in Note 5.

Generally, and subject to the terms of the series A preferred stock, at any time prior to January 15, 2021, holders may elect to convert each share of the series A preferred stock into shares of our common stock at the minimum conversion rate of 0.7629 shares of our common stock per share of the series A preferred stock (or an aggregate of approximately 13.2 million common shares, if all outstanding series A preferred stock were converted early), subject to anti-dilution adjustments.

We discuss the terms of the series A preferred stock in Note 18 of the Notes to Consolidated Financial Statements in the Annual Report.

6.75 % Mandatory Convertible Preferred Stock, Series B

On July 13, 2018, we issued 5,750,000 shares of our series B preferred stock in a registered public offering at $ 100.00 per share (or $ 98.35 per share after deducting underwriting discounts), including 750,000 shares purchased by the underwriters directly from us as a result of fully exercising their option to purchase such shares from us solely to cover overallotments. Each share of series B preferred stock has a liquidation value of $ 100.00 . We used the net proceeds of approximately $ 566 million (net of underwriting discounts and equity issuance costs of $ 9 million ) to repay commercial paper, to fund working capital and for other general corporate purposes.

Mandatory Conversion. Unless earlier converted, each share of the series B preferred stock will automatically convert on the mandatory conversion date of July 15, 2021 into not less than 0.7326 shares and not more than 0.8791 shares of our common stock, subject to anti-dilution adjustments. The number of shares of our common stock issuable on conversion of the series B preferred stock will be determined based on the volume-weighted average market value per share of our common stock over the 20-consecutive trading day period beginning on and including the 21st scheduled trading day immediately preceding July 15, 2021. The following table illustrates the conversion rate per share of the series B preferred stock, subject to certain anti-dilution adjustments.

CONVERSION RATES
Applicable market value per share of our common stock	Conversion rate (number of shares of our common stock to be received upon conversion of each share of series B preferred stock)
Greater than $136.50 (which is the threshold appreciation price)	0.7326 shares (approximately equal to $100.00 divided by the threshold appreciation price)
Equal to or less than $136.50 but greater than or equal to $113.75	Between 0.7326 and 0.8791 shares, determined by dividing $100.00 by the applicable market value of our common stock
Less than $113.75 (which is the initial price)	0.8791 shares (approximately equal to $100.00 divided by the initial price)

Conversion at the Option of the Holder. Generally, and subject to the terms of the series B preferred stock, at any time prior to July 15, 2021, holders may elect to convert each share of the series B preferred stock into shares of our common stock at the minimum conversion rate of 0.7326 shares of our common stock per share of the series B preferred stock (or an aggregate of approximately 4.2 million common shares, if all outstanding series B preferred stock were converted early), subject to anti-dilution adjustments. Further, if holders elect to convert any shares of the series B preferred stock during a specified period beginning on the effective date of a fundamental change, as defined in the certificate of determination of preferences of the series B preferred stock, such shares of the series B preferred stock will be converted into shares of our common stock at a fundamental change conversion rate, and the holders will also be entitled to receive a fundamental change dividend make-whole amount and accumulated dividend amount.

Dividends. Dividends on the series B preferred stock are payable quarterly on a cumulative basis when, as and if declared by our board of directors. The first quarterly dividend was paid on October 15, 2018. We may pay quarterly declared dividends in cash or, subject to certain limitations, in shares of our common stock, no par value, or in any combination of cash and shares of our common stock. Shares of common stock used to pay dividends will be valued at 97 percent of the volume-weighted average price per share over the five-consecutive trading day period beginning on, and including the sixth trading day prior to, the applicable dividend payment date. The holders of series B preferred stock do not have voting rights. However, under certain circumstances regarding nonpayment for six or more dividend periods, whether or not consecutive, the authorized number of directors on our board of directors will automatically be increased by two and the holders of the series B preferred stock, voting together as a single class with holders of any and all other outstanding preferred stock of equal rank having similar voting rights (which currently consists of the series A preferred stock), will be entitled to elect two directors to fill such newly created directorships. This right shall terminate when all accumulated dividends have been paid in full and the authorized number of directors shall automatically decrease by two, subject to the revesting of that right in the event of each subsequent nonpayment.

Ranking. The series B preferred stock ranks with respect to dividend rights and distribution rights upon our liquidation, winding-up or dissolution:

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

▪ on parity with our series A preferred stock, including our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise;

▪ junior to our capital stock established in the future, if the terms provide that such class of series will rank senior to the series B preferred stock;

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

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

Sempra Energy Common Stock Offerings

On January 9, 2018, we completed the offering of 23,364,486 shares of our common stock, no par value, in a registered public offering at $ 107.00 per share (approximately $ 105.07 per share after deducting underwriting discounts), pursuant to forward sale agreements with each of Morgan Stanley & Co. LLC, an affiliate of RBC Capital Markets, LLC and an affiliate of Barclays Capital Inc. (the forward purchasers). The shares offered pursuant to the forward sale agreements were borrowed by the underwriters and therefore are not newly issued shares. The underwriters of the offering fully exercised the option we granted them to purchase an additional 3,504,672 shares of common stock directly from us solely to cover overallotments. After the offering, including the issuance of shares pursuant to the exercise of the overallotment option, the aggregate shares of common stock sold in the offering totaled 26,869,158 . We received net proceeds of $ 367 million (net of underwriting discounts and equity issuance costs of $ 8 million ) from the sale of shares to cover overallotments. We did not initially receive any proceeds from the sale of our common stock sold pursuant to the forward sale agreements.

In the first quarter of 2018, we settled approximately $ 900 million (net of underwriting discounts of $ 16 million ) and in the second quarter of 2018, we settled approximately $ 800 million (net of underwriting discounts of $ 14 million ) of forward sales under the forward sale agreements by delivering 8,556,630 shares and 7,651,671 shares, respectively, of newly issued Sempra Energy common stock at forward sale prices ranging from approximately $ 104.53 to approximately $ 105.18 per share.

We used the net proceeds from the sale of shares in the January 2018 offering and from the settlement of forward sales in the first quarter of 2018 under the forward sale agreements to fund a portion of the Merger Consideration, as we discuss in Note 5. We used the net proceeds from the settlement of forward sales in the second quarter of 2018 to repay long-term debt maturing in June 2018 and to repay commercial paper used to fund a portion of the Merger Consideration.

On July 13, 2018, we completed the offering of 9,750,000 shares of our common stock, no par value, in a registered public offering at $ 113.75 per share (approximately $ 111.87 per share after deducting underwriting discounts), pursuant to forward sale agreements with an affiliate of Citigroup Global Markets Inc. and an affiliate of J.P. Morgan Securities LLC (the forward purchasers). The shares offered pursuant to the forward sale agreements were borrowed by the underwriters and therefore are not newly issued shares. The underwriters of the offering fully exercised the option we granted them to purchase an additional 1,462,500 shares of common stock directly from us solely to cover overallotments. After the offering, including the issuance of shares pursuant to the exercise of the overallotment option, the aggregate shares of common stock sold in the offering totaled 11,212,500 . We received net proceeds of $ 164 million (net of underwriting discounts and equity issuance costs of $ 3 million ) from the sale of shares to cover overallotments. We did not initially receive any proceeds from the sale of our common stock sold pursuant to the forward sale agreements. We used the net proceeds from the sale of the overallotment shares to the underwriters, and we expect to use the net proceeds from the sale of shares of our common stock pursuant to the forward sale agreements, to repay commercial paper, to fund working capital and for other general corporate purposes.

As of November 7, 2018, a total of 16,906,185 shares of Sempra Energy common stock from our January 2018 and July 2018 offerings remain subject to future settlement under these forward sale agreements, which may be settled on one or more dates specified by us occurring no later than December 15, 2019, which is the final settlement date under the agreements. Although we expect to settle the forward sale agreements entirely by the physical delivery of shares of our common stock in exchange for cash proceeds, we may, subject to certain conditions, elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreements. The forward sale agreements are also subject to acceleration by the forward purchasers upon the occurrence of certain events.

SoCalGas Preferred Stock

The preferred stock at SoCalGas is presented at Sempra Energy as a noncontrolling interest. Sempra Energy records charges against income related to NCI for preferred stock dividends declared by SoCalGas. We provide additional information regarding preferred stock in Note 11 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Noncontrolling Interests

Ownership interests that are held by owners other than Sempra Energy and SDG&E in subsidiaries or entities consolidated by them are accounted for and reported as NCI. As a result, NCI is reported as a separate component of equity on the Condensed Consolidated Balance Sheets. Earnings or losses attributable to NCI are separately identified on the Condensed Consolidated Statements of Operations, and net income or loss and comprehensive income or loss attributable to NCI are separately identified on the Condensed Consolidated Statements of Comprehensive Income (Loss) and Condensed Consolidated Statements of Changes in Equity.

The following table provides information on noncontrolling ownership interests held by others (not including preferred shareholders) in Other Noncontrolling Interests in Total Equity on Sempra Energy’s Condensed Consolidated Balance Sheets.

OTHER NONCONTROLLING INTERESTS
(Dollars in millions)
	Percent ownership held by noncontrolling interests		Equity (deficit) held by noncontrolling interests
	September 30, 2018	December 31, 2017	September 30, 2018		December 31, 2017
SDG&E:
Otay Mesa VIE	100 %	100 %	$ 37		$ 28
Sempra South American Utilities:
Chilquinta Energía subsidiaries (1)	19.8 – 43.4	22.9 – 43.4	23		24
Luz del Sur	16.4	16.4	193		189
Tecsur	9.8	9.8	4		4
Sempra Mexico:
IEnova (2)(3)	33.6	33.6	1,564		1,532
Sempra Renewables:
Tax equity arrangements – wind (4)	NA	NA	161		181
Tax equity arrangements – solar (4)	NA	NA	495		450
PXiSE Energy Solutions, LLC	11.1	—	1		—
Sempra LNG & Midstream:
Bay Gas	9.1	9.1	8		28
Liberty Gas Storage, LLC	24.6	24.6	( 12	)	14
Total Sempra Energy			$ 2,474		$ 2,450

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

(2) IEnova has a subsidiary with a 10 -percent NCI held by others. The equity held by NCI is negligible at both September 30, 2018 and December 31, 2017.

(3) IEnova has a subsidiary with a 49 -percent NCI held by others. The equity held by NCI is $ 13 million at September 30, 2018 .

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

Sempra Renewables

In the fourth quarter of 2017, Sempra Renewables entered into a membership interest purchase agreement with a financial institution to form a tax equity limited liability company that includes a Sempra Renewables portfolio of four solar power generation projects located in Fresno County, California. Sempra Renewables received tax equity funding for three of the four phases in the fourth quarter of 2017. Additional funding of $ 85 million , net of offering costs, for the fourth phase of the tax equity arrangement occurred in April 2018. Sempra Renewables continues to consolidate the entity and report NCI representing the financial institution’s membership interest in the tax equity arrangement.

TRANSACTIONS WITH AFFILIATES

We summarize amounts due from and to unconsolidated affiliates at Sempra Energy Consolidated, SDG&E and SoCalGas in the following table.

AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	September 30, 2018		December 31, 2017
Sempra Energy Consolidated:
Total due from various unconsolidated affiliates – current	$ 43		$ 37
Sempra South American Utilities (1) :
Eletrans – 4% Note (2)	$ 40		$ 103
Other related party receivables	1		1
Sempra Mexico (1) :
IMG – Note due March 15, 2022 (3)	638		487
Energía Sierra Juárez – Note (4)	3		7
Total due from unconsolidated affiliates – noncurrent	$ 682		$ 598
Total due to various unconsolidated affiliates – current	$ ( 7	)	$ ( 7	)
Sempra Mexico (1) :
Total due to unconsolidated affiliates – noncurrent – TAG – Note due December 20, 2021 (5)	$ ( 36	)	$ ( 35	)
SDG&E:
Total due from unconsolidated affiliates – current – SoCalGas	$ 1		$ —
Sempra Energy	$ ( 45	)	$ ( 30	)
SoCalGas	—		( 4	)
Enova Corporation	( 250	)	—
Various affiliates	( 8	)	( 6	)
Total due to unconsolidated affiliates – current	$ ( 303	)	$ ( 40	)
Income taxes due from Sempra Energy (6)	$ 44		$ 27
SoCalGas:
SDG&E	$ —		$ 4
Sempra Energy (7)	49		—
Total due from unconsolidated affiliates – current	$ 49		$ 4
SDG&E	$ ( 1	)	$ —
Sempra Energy	—		( 35	)
Pacific Enterprises	( 50	)	—
Total due to unconsolidated affiliates – current	$ ( 51	)	$ ( 35	)
Income taxes due from Sempra Energy (6)	$ 3		$ 10

(1) Amounts include principal balances plus accumulated interest outstanding.

(2) U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans, comprising joint ventures of Chilquinta Energía.

(3) Mexican peso-denominated revolving line of credit for up to $ 14.2 billion Mexican pesos or approximately $ 757 million U.S. dollar-equivalent, at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus 220 bps ( 10.37 percent at September 30, 2018 ), to finance construction of the natural gas marine pipeline.

(4) U.S. dollar-denominated loan, at a variable interest rate based on the 30-day LIBOR plus 637.5 bps ( 8.63 percent at September 30, 2018 ) with no stated maturity date, to finance the first phase of the Energía Sierra Juárez wind project, which is a joint venture of IEnova.

(5) U.S. dollar-denominated loan, at a variable interest rate based on the 6-month LIBOR plus 290 bps ( 5.50 percent at September 30, 2018 ).

(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 September 30, 2018 , net receivable included outstanding advances to Sempra Energy of $ 88 million at an interest rate of 2.35 percent .

The following table summarizes revenues and cost of sales from unconsolidated affiliates.

REVENUES AND COST OF SALES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	Three months ended September 30,		Nine months ended September 30,
	2018	2017	2018	2017
Revenues:
Sempra Energy Consolidated	$ 17	$ 13	$ 49	$ 28
SDG&E	1	2	4	6
SoCalGas	15	21	47	56
Cost of Sales:
Sempra Energy Consolidated	$ 9	$ 8	$ 36	$ 36
SDG&E	21	16	56	55

Guarantees

Sempra Energy has provided guarantees to certain of its joint ventures, entered into guarantees related to the financing of the Cameron LNG JV project and provided guarantees to certain third parties for the benefit of IMG, as we discuss in Note 6 below and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

OTHER INCOME, NET

Other Income, Net on the Condensed Consolidated Statements of Operations consisted of the following:

OTHER INCOME, NET
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017 (1)		2018		2017 (1)
Sempra Energy Consolidated:
Allowance for equity funds used during construction	$ 23		$ 27		$ 79		$ 139
Investment gains (2)	8		13		13		43
Gains on interest rate and foreign exchange instruments, net	39		5		46		99
Foreign currency transaction gains (losses), net (3)	28		( 10	)	17		7
Non-service component of net periodic benefit (cost) credit	( 4	)	( 1	)	35		21
Interest on regulatory balancing accounts, net	1		1		2		3
Sundry, net	2		5		4		10
Total	$ 97		$ 40		$ 196		$ 322
SDG&E:
Allowance for equity funds used during construction	$ 15		$ 15		$ 49		$ 46
Non-service component of net periodic benefit credit	8		4		25		12
Interest on regulatory balancing accounts, net	2		1		4		3
Sundry, net	( 1	)	—		( 1	)	—
Total	$ 24		$ 20		$ 77		$ 61
SoCalGas:
Allowance for equity funds used during construction	$ 8		$ 11		$ 30		$ 33
Non-service component of net periodic benefit (cost) credit	( 1	)	5		27		23
Interest on regulatory balancing accounts, net	( 1	)	—		( 2	)	—
Sundry, net	( 3	)	( 3	)	( 6	)	( 5	)
Total	$ 3		$ 13		$ 49		$ 51

(1) As adjusted for the retrospective adoption of ASU 2017-07, which we discuss in Note 2.

(2) 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 O&M on the Condensed Consolidated Statements of Operations.

(3) Includes gains of $ 33 million and $ 25 million in the three months and nine months ended September 30, 2018, respectively, and losses of $ 6 million and a negligible amount in the three months and nine months ended September 30, 2017, respectively, from translation to U.S. dollars of a Mexican peso-denominated loan to the IMG joint venture, which are offset by corresponding amounts included in Equity Earnings on the Condensed Consolidated Statements of Operations.

INCOME TAXES

INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
Sempra Energy Consolidated:
Income tax expense (benefit)	$ 167		$ ( 84	)	$ ( 127	)	$ 378
Income (loss) before income taxes and equity earnings
of unconsolidated subsidiaries	$ 427		$ 5		$ ( 15	)	$ 1,154
Equity (losses) earnings, before income tax (1)	( 52	)	10		( 236	)	31
Pretax income (loss)	$ 375		$ 15		$ ( 251	)	$ 1,185
Effective income tax rate	45	%	( 560	)%	51	%	32 %
SDG&E:
Income tax expense (benefit)	$ 53		$ ( 72	)	$ 151		$ 72
Income (loss) before income taxes	$ 269		$ ( 91	)	$ 682		$ 363
Effective income tax rate	20	%	79	%	22	%	20 %
SoCalGas:
Income tax (benefit) expense	$ ( 7	)	$ ( 14	)	$ 75		$ 103
(Loss) income before income taxes	$ ( 21	)	$ ( 7	)	$ 320		$ 372
Effective income tax rate	33	%	200	%	23	%	28 %

(1) We discuss how we recognize equity earnings in Note 6.

Sempra Energy, SDG&E and SoCalGas record income taxes for interim periods utilizing a forecasted ETR anticipated for the full year, in accordance with U.S. GAAP. Unusual and infrequent items and items that cannot be reliably estimated are recorded in the interim period in which they occur, which can result in variability in the ETR.

For SDG&E and SoCalGas, the CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the ETR. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the ETR. The following items are subject to flow-through treatment:

▪ repairs expenditures related to a certain portion of utility plant assets

▪ the equity portion of AFUDC

▪ a portion of the cost of removal of utility plant assets

▪ utility self-developed software expenditures

▪ depreciation on a certain portion of utility plant assets

▪ state income taxes

The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico has similar flow-through treatment.

We record income tax (expense) benefit from the transactional effects of foreign currency and inflation. Such effects are partially mitigated by net gains (losses) from foreign currency derivatives that are hedging Sempra Mexico parent’s exposure to movements in the Mexico peso from its controlling interest in IEnova.

On December 22, 2017, the TCJA was signed into law. The TCJA reduced the U.S. statutory corporate federal income tax rate from 35 percent to 21 percent , effective January 1, 2018. In the fourth quarter of 2017, we recorded $ 870 million of income tax expense related to the effects of the TCJA. This expense was provisional, using our best estimates and the information available to us through the date those financial statements were issued. As permitted by and in accordance with the guidance issued by the SEC and codified in ASU 2018-05, we may adjust our provisional estimates in reporting periods throughout 2018 as we complete our analysis and as more information becomes available, and these adjustments may affect earnings. Events and information that may still result in adjustments to our provisional estimates include interpretations of the TCJA by the U.S. Department of the Treasury, conformity by the states of the application of the TCJA, assessment of the impact of the TCJA global intangible low-taxed income provisions on the realizability of deferred tax assets, and the finalization of our calculation of foreign undistributed earnings. In the nine months ended September 30, 2018, Sempra Energy recorded $ 25 million of additional income tax expense to adjust the provisional estimates recorded in 2017. Additionally, SDG&E and SoCalGas adjusted their provisional estimates relating to the remeasurement of deferred income taxes. In the nine months ended September 30, 2018, SDG&E’s deferred tax liabilities decreased by $ 38 million and SoCalGas’ deferred tax liabilities increased by $ 5 million , with each amount offset by a change in their respective regulatory liabilities.

We provide additional information about the TCJA and our accounting for income taxes in Notes 1 and 6 of the Notes to Consolidated Financial Statements in the Annual Report.

NOTE 2. NEW ACCOUNTING STANDARDS

We describe below recent accounting pronouncements that have had or may have a significant effect on our financial condition, results of operations, cash flows or disclosures.

ASU 2014-09, “Revenue from Contracts with Customers,” ASU 2015-14, “Deferral of the Effective Date,” ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” ASU 2016-10, “Identifying Performance Obligations and Licensing” and ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients”: ASU 2014-09 adds ASC 606 to provide accounting guidance for the recognition of revenue from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers. The guidance also provides a model for the measurement and recognition of gains and losses on the sale of certain nonfinancial assets, such as property and equipment, including real estate. This guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. Amending ASU 2014-09, ASU 2016-08 clarifies the implementation guidance on principal versus agent considerations, ASU 2016-10 clarifies the determination of whether a good or service is separately identifiable from other promises and revenue recognition related to licenses of intellectual property, and ASU 2016-12 provides guidance on transition, collectability, noncash consideration, and the presentation of sales and other similar taxes. The ASUs are codified in ASC 606.

We adopted ASC 606 on January 1, 2018, applying the modified retrospective transition method to all contracts as of January 1, 2018 and elected to use certain practical expedients available under the transition guidance. The impact from adoption was not material to our financial statements, and the timing of our revenue recognition has remained materially consistent before and after the adoption of ASC 606. The new revenue standard provides specific guidance for combining contracts, which resulted in a prospective reclassification between cost of sales and revenues within our Sempra LNG & Midstream segment. This reclassification had no impact on Sempra Energy’s consolidated revenues or cost of sales. Our additional disclosures about the nature, amount, timing and uncertainty of revenues arising from contracts with customers are included in Note 3.

ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities” and ASU 2018-03, “Technical Corrections and Improvements to Financial Instruments – Overall”: In addition to the presentation and disclosure requirements for financial instruments, ASU 2016-01 requires entities to measure equity investments, other than those accounted for under the equity method, at fair value and recognize changes in fair value in net income. Entities will no longer be able to use the cost method of accounting for equity securities. However, for equity investments without readily determinable fair values that do not qualify for the practical expedient to estimate fair value using net asset value per share, entities may elect a measurement alternative that will allow those investments to be recorded at cost, less impairment, and adjusted for subsequent observable price changes. ASU 2018-03 clarifies that the prospective transition approach for equity investments without readily determinable fair values is meant only for instances in which the measurement alternative is elected. Entities must record a cumulative-effect adjustment to the balance sheet as of the beginning of the first reporting period in which the standard is adopted, except for equity investments without readily determinable fair values, for which the guidance will be applied prospectively.

We adopted ASU 2016-01 and ASU 2018-03 on January 1, 2018. Sempra Energy recognized a cumulative-effect adjustment to decrease Retained Earnings and Other Investments as of January 1, 2018 by $ 1 million .

ASU 2016-02, “Leases,” ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” ASU 2018-10, “Codification Improvements to Topic 842, Leases” and ASU 2018-11, “Leases (Topic 842): Targeted Improvements”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the fixed lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting and ASC 606. ASU 2016-02 also requires new qualitative and quantitative disclosures for both lessees and lessors. ASU 2018-10 makes technical corrections and clarifications to the accounting guidance in ASC 842.

For public entities, these ASUs are effective for fiscal years beginning after December 15, 2018, including interim periods therein, with early adoption permitted. ASU 2016-02 requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. ASU 2018-11 provides entities an optional transition method to apply the new guidance as of the adoption date, rather than as of the earliest period presented. In transition, entities may elect certain practical expedients when applying ASU 2016-02. These include a package of practical expedients that must be applied in its entirety to all leases commencing before the effective date, unless the lease is modified, to not reassess (a) the existence of a lease, (b) lease classification or (c) determination of initial direct costs, which effectively allows entities to carryforward accounting conclusions under previous U.S. GAAP. ASU 2016-02 also includes a practical expedient to use hindsight in making judgments when determining the lease term and any long-lived asset impairment. ASU 2018-01 allows entities to elect a practical expedient that would exclude application of ASU 2016-02 to land easements that existed prior to its adoption, if they were not accounted for as leases under previous U.S. GAAP. In addition, ASU 2016-02 and ASU 2018-11 provide practical expedients to the lessee and lessor, respectively, for separating lease and non-lease components.

We are currently evaluating the effect of the standards on our ongoing financial reporting and plan to adopt the standards on January 1, 2019, using the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. As part of our evaluation, we formed a steering committee comprised of members from Sempra Energy’s business units, have compiled our population of contracts and are preparing our lease accounting assessments. Based on our assessment to date, we have determined that we will elect the package of practical expedients, the land easement practical expedient, and the practical expedient to not separate lease and non-lease components available under the transition guidance described above, but will not elect to use the hindsight practical expedient.

ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13 changes how entities will measure credit losses for most financial assets and certain other instruments. The standard introduces an “expected credit loss” impairment model that requires immediate recognition of estimated credit losses expected to occur over the remaining life of most financial assets measured at amortized cost, including trade and other receivables, loan commitments and financial guarantees. ASU 2016-13 also requires use of an allowance to record estimated credit losses on available-for-sale debt securities and expands disclosure requirements regarding an entity’s assumptions, models and methods for estimating the credit losses.

For public entities, ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, including interim periods therein, with early adoption permitted for fiscal years beginning after December 15, 2018. The amendments are to be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings at the beginning of the first reporting period in the year of adoption. We are currently evaluating the effect of the standard on our ongoing financial reporting and plan to adopt the standard on January 1, 2020.

ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments” and ASU 2016-18, “Restricted Cash”: ASU 2016-15 provides guidance on how certain cash receipts and cash payments are to be presented and classified in the statement of cash flows to reduce diversity in practice.

ASU 2016-18 requires amounts classified as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. A reconciliation between the balance sheet and the statement of cash flows must be disclosed when the balance sheet includes more than one line item for cash, cash equivalents, restricted cash and restricted cash equivalents.

We early adopted ASU 2016-15 and ASU 2016-18 on a retrospective basis in the fourth quarter of 2017. Neither ASU impacted SoCalGas’ Condensed Statements of Cash Flows. Upon adoption of these ASUs, Sempra Energy’s and SDG&E’s Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 were impacted as follows:

IMPACT FROM ADOPTION OF ASU 2016-15 AND ASU 2016-18
(Dollars in millions)
	Nine months ended September 30, 2017
	As previously reported		Effect of adoption		As adjusted
Sempra Energy Condensed Consolidated Statement of Cash Flows:
Cash flows from operating activities:
Changes in other noncurrent assets and liabilities, net (1)	$ ( 66	)	$ ( 6	)	$ ( 72	)
Net cash provided by operating activities	2,710		( 6	)	2,704
Cash flows from investing activities:
Increases in restricted cash	( 293	)	293		—
Decreases in restricted cash	298		( 298	)	—
Other	1		5		6
Effect of exchange rate changes on cash and cash equivalents	9		( 9	)	—
Effect of exchange rate changes on cash, cash equivalents and restricted cash	—		11		11
Decrease in cash and cash equivalents	( 160	)	160		—
Decrease in cash, cash equivalents, and restricted cash	—		( 164	)	( 164	)
Cash and cash equivalents, January 1	349		( 349	)	—
Cash, cash equivalents and restricted cash, January 1	—		425		425
Cash and cash equivalents, September 30	189		( 189	)	—
Cash, cash equivalents and restricted cash, September 30	—		261		261
SDG&E Condensed Consolidated Statement of Cash Flows:
Cash flows from operating activities:
Changes in other noncurrent assets and liabilities, net (1)	$ ( 4	)	$ ( 6	)	$ ( 10	)
Net cash provided by operating activities	1,178		( 6	)	1,172
Cash flows from investing activities:
Increases in restricted cash	( 21	)	21		—
Decreases in restricted cash	18		( 18	)	—
Other	—		6		6
Net cash used in investing activities	( 1,094	)	9		( 1,085	)
Increase in cash and cash equivalents	10		( 10	)	—
Increase in cash, cash equivalents, and restricted cash	—		13		13
Cash and cash equivalents, January 1	8		( 8	)	—
Cash, cash equivalents and restricted cash, January 1	—		20		20
Cash and cash equivalents, September 30	18		( 18	)	—
Cash, cash equivalents and restricted cash, September 30	—		33		33

(1) “As previously reported” amounts in “Changes in other assets” and “Changes in other liabilities” have been combined into one line, “Changes in other noncurrent assets and liabilities, net” to conform to current year presentation.

ASU 2017-04, “Simplifying the Test for Goodwill Impairment”: ASU 2017-04 removes the second step of the goodwill impairment test, which requires a hypothetical purchase price allocation. An entity will be required to apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill. For public entities, ASU 2017-04 is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. The amendments are to be applied on a prospective basis. We have not yet selected the year in which we will adopt the standard.

ASU 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”: ASU 2017-05 clarifies the scope of accounting for the derecognition or partial sale of nonfinancial assets to exclude all businesses and nonprofit activities. ASU 2017-05 also provides a definition for in-substance nonfinancial assets and additional guidance on partial sales of nonfinancial assets. We adopted the standard in conjunction with our adoption of ASC 606 on January

1, 2018 using the modified retrospective transition method and it did not materially affect our financial condition, results of operations or cash flows.

ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”: ASU 2017-07 requires the service cost component of net periodic benefit costs to be presented in the same income statement line item as other employee compensation costs arising from services rendered during the period and the other components of net periodic benefit costs to be presented separately outside of operating income. The guidance also allows only the service cost component to be eligible for capitalization. Amendments are to be applied retrospectively for presentation of costs and prospectively for capitalization of service costs. The guidance allows a practical expedient that permits use of previously disclosed service costs and other costs from the pension and other postretirement benefit plan disclosure in the comparative periods as appropriate estimates when retrospectively changing the presentation of these costs in the statements of operations. We adopted the standard on January 1, 2018 and elected the practical expedient available under the transition guidance.

Upon adoption of ASU 2017-07, our Condensed Consolidated Statements of Operations were impacted as follows:

IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Three months ended September 30, 2017						Nine months ended September 30, 2017
	As previously reported		Effect of adoption		As adjusted		As previously reported	Effect of adoption		As adjusted
Sempra Energy:
Operation and maintenance (1)	$ 760		$ ( 1	)	$ 759		$ 2,205	$ 21		$ 2,226
Other income, net	41		( 1	)	40		301	21		322
SDG&E:
Operation and maintenance	$ 249		$ 4		$ 253		$ 713	$ 12		$ 725
Total operating expenses	1,290		4		1,294		2,886	12		2,898
Operating (loss) income	( 54	)	( 4	)	( 58	)	465	( 12	)	453
Other income, net	16		4		20		49	12		61
SoCalGas:
Operation and maintenance	$ 355		$ 5		$ 360		$ 1,044	$ 23		$ 1,067
Total operating expenses	674		5		679		2,275	23		2,298
Operating income	10		( 5	)	5		420	( 23	)	397
Other income, net	8		5		13		28	23		51

(1) “As previously reported” amounts in “Operation and maintenance” and “Gain on sale of assets” have been combined into one line, “Operation and maintenance” to conform to current year presentation.

ASU 2017-12, “Targeted Improvements to Accounting for Hedging Activities”: ASU 2017-12 changes the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge accounting results. More specifically, the guidance expands the exposures that can be hedged to align with an entity’s risk management strategies, alleviates documentation requirements, eliminates the concept of recognizing periodic hedge ineffectiveness for cash flow and net investment hedges and requires entities to present the entire change in the fair value of a hedging instrument in the same income statement line item as the earnings effect of the hedged item. Transition elections are available for all hedges that exist at the date of adoption. We early adopted ASU 2017-12 on January 1, 2018 by applying the modified retrospective approach to the accounting for existing hedging relationships. Sempra Energy recognized a cumulative-effect adjustment to increase Retained Earnings and Accumulated Other Comprehensive Loss as of January 1, 2018 by $ 3 million .

ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”: ASU 2018-02 contains amendments that allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the TCJA. Under ASU 2018-02, an entity will be required to provide certain disclosures regarding stranded tax effects, including its accounting policy related to releasing the income tax effects from AOCI. The amendments in this update can be applied either as of the beginning of the period of adoption or retrospectively as of the date of enactment of the TCJA and to each period in which the effect of the TCJA is recognized. For public entities, ASU 2018-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods therein, with early adoption permitted. We will adopt ASU 2018-02 on a prospective basis on January 1, 2019 and will reclassify the income tax effects of the TCJA from AOCI to retained earnings.

We expect the impact from adoption of ASU 2018-02 on January 1, 2019 to be as follows:

▪ Sempra Energy: increase of $ 42 million to beginning Retained Earnings, $ 2 million to noncurrent Regulatory Liabilities and

$ 44 million to Accumulated Other Comprehensive Loss;

▪ SDG&E: increase of $ 2 million to beginning Retained Earnings and Accumulated Other Comprehensive Loss; and

▪ SoCalGas: increase of $ 2 million to beginning Retained Earnings, $ 2 million to noncurrent Regulatory Liabilities and $ 4 million to Accumulated Other Comprehensive Loss.

ASU 2018-05, “Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118”: As a result of the TCJA, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118), which provides guidance on accounting for the TCJA’s impact. Under SAB 118, an entity may apply an approach similar to the measurement period in a business combination. That is, an entity would record those impacts for which the accounting is complete. For matters that are not certain, the entity would either (1) recognize provisional amounts to the extent that they are reasonably estimable and adjust them over time as more information becomes available, or (2) for any specific income tax effects of the TCJA for which a reasonable estimate cannot be determined, continue to apply ASC 740, Income Taxes , on the basis of the provisions of the tax laws that were in effect immediately before the TCJA was signed into law; the entity would not adjust current or deferred taxes for those tax effects of the TCJA until a reasonable estimate can be determined. ASU 2018-05 amends ASC 740 by incorporating SAB 118 and is effective upon issuance. We are applying SAB 118 and ASU 2018-05. The income tax effects of the TCJA that we recorded in 2017 were provisional, and we have adjusted and may continue to adjust our provisional estimates in reporting periods throughout 2018, as we discuss in Note 1.

ASU 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurement” and ASU 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans”: ASU 2018-13 and ASU 2018-14 are intended to improve the effectiveness of disclosures. ASU 2018-13 adds, removes and modifies certain disclosure requirements related to fair value measurements in ASC 820. ASU 2018-14 adds, removes, and clarifies certain disclosure requirements related to defined benefit pension and other postretirement plans. For public entities, ASU 2018-13 is effective for annual reporting periods beginning after December 15, 2019, including interim periods therein, with early adoption permitted for eliminated or modified disclosures. For public entities, ASU 2018-14 is effective for annual reporting periods beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the effect of the standards on our financial statement disclosures and have not yet selected the year in which we will adopt the standards.

NOTE 3. REVENUES

The following table disaggregates our revenues from contracts with customers by major service line, market and timing of recognition and provides a reconciliation to total revenues by segment.

DISAGGREGATED REVENUES
(Dollars in millions)
	Three months ended September 30, 2018
	SDG&E		SoCalGas	Sempra South American Utilities	Sempra Mexico	Sempra Renewables	Sempra LNG & Midstream	Consolidating adjustments		Sempra Energy Consolidated
By major service line:
Utilities	$ 1,577		$ 719	$ 358	$ 17	$ —	$ —	$ ( 16	)	$ 2,655
Midstream	—		—	—	194	—	82	( 71	)	205
Renewables	—		—	—	32	14	1	( 1	)	46
Other	—		—	16	71	—	1	( 2	)	86
Revenues from contracts with customers	$ 1,577		$ 719	$ 374	$ 314	$ 14	$ 84	$ ( 90	)	$ 2,992
By market:
Electric	$ 1,486		$ —	$ 374	$ 100	$ 14	$ 2	$ ( 4	)	$ 1,972
Gas	91		719	—	214	—	82	( 86	)	1,020
Revenues from contracts with customers	$ 1,577		$ 719	$ 374	$ 314	$ 14	$ 84	$ ( 90	)	$ 2,992
By timing of recognition:
Over time	$ 1,549		$ 688	$ 370	$ 314	$ 14	$ 84	$ ( 90	)	$ 2,929
Point in time	28		31	4	—	—	—	—		63
Revenues from contracts with customers	$ 1,577		$ 719	$ 374	$ 314	$ 14	$ 84	$ ( 90	)	$ 2,992
Revenues from contracts with customers	$ 1,577		$ 719	$ 374	$ 314	$ 14	$ 84	$ ( 90	)	$ 2,992
Utilities regulatory revenues	( 278	)	83	—	—	—	—	—		( 195	)
Other revenues	—		—	1	96	24	63	( 41	)	143
Total revenues	$ 1,299		$ 802	$ 375	$ 410	$ 38	$ 147	$ ( 131	)	$ 2,940
	Nine months ended September 30, 2018
By major service line:
Utilities	$ 3,707		$ 2,529	$ 1,136	$ 58	$ —	$ —	$ ( 51	)	$ 7,379
Midstream	—		—	—	484	—	171	( 105	)	550
Renewables	—		—	—	85	37	2	( 1	)	123
Other	—		—	50	142	—	5	( 5	)	192
Revenues from contracts with customers	$ 3,707		$ 2,529	$ 1,186	$ 769	$ 37	$ 178	$ ( 162	)	$ 8,244
By market:
Electric	$ 3,335		$ —	$ 1,186	$ 224	$ 37	$ 7	$ ( 9	)	$ 4,780
Gas	372		2,529	—	545	—	171	( 153	)	3,464
Revenues from contracts with customers	$ 3,707		$ 2,529	$ 1,186	$ 769	$ 37	$ 178	$ ( 162	)	$ 8,244
By timing of recognition:
Over time	$ 3,625		$ 2,438	$ 1,173	$ 769	$ 37	$ 156	$ ( 152	)	$ 8,046
Point in time	82		91	13	—	—	22	( 10	)	198
Revenues from contracts with customers	$ 3,707		$ 2,529	$ 1,186	$ 769	$ 37	$ 178	$ ( 162	)	$ 8,244
Revenues from contracts with customers	$ 3,707		$ 2,529	$ 1,186	$ 769	$ 37	$ 178	$ ( 162	)	$ 8,244
Utilities regulatory revenues	( 302	)	171	—	—	—	—	—		( 131	)
Other revenues	—		—	4	259	66	152	( 128	)	353
Total revenues	$ 3,405		$ 2,700	$ 1,190	$ 1,028	$ 103	$ 330	$ ( 290	)	$ 8,466

REVENUES FROM CONTRACTS WITH CUSTOMERS

Our revenues from contracts with customers are primarily related to the generation, transmission and distribution of electricity and transmission, distribution and storage of natural gas through our regulated utilities. We also provide other midstream and renewable energy-related services. We assess our revenues on a contract-by-contract as well as a portfolio basis to determine the nature, amount, timing and uncertainty, if any, of revenues being recognized.

We generally recognize revenues when performance of the promised commodity service is provided to our customers and invoice our customers for an amount that reflects the consideration we are entitled to in exchange for those services. We consider the delivery and transmission of electricity and natural gas and providing of natural gas storage services as ongoing and integrated services. Generally, electricity or natural gas services are received and consumed by the customer simultaneously. Our performance obligations related to these services are satisfied over time and represent a series of distinct services that are substantially the same and that have the same pattern of transfer to the customers. We recognize revenue based on units delivered, as the satisfaction of our performance obligations can be directly measured by the amount of electricity or natural gas delivered to the customer. In most cases, the right to consideration from the customer directly corresponds to the value transferred to the customer and we recognize revenue in the amount that we have the right to invoice. We provide further details of our revenue streams below.

The payment terms in our customer contracts vary. Typically, we have an unconditional right to customer payments, which are due after the performance obligation to the customer is satisfied. The term between invoicing and when payment is due is typically between 10 and 90 days.

We have elected the practical expedient to exclude sales and usage-based taxes from revenues. In addition, the California Utilities pay franchise fees to operate in various municipalities. The California Utilities bill these franchise fees to their customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of the California Utilities’ ability to collect from the customer, are accounted for on a gross basis and reflected in utilities revenues from contracts with customers and operating expense.

Utilities Revenues

Utilities revenues represent the majority of our consolidated revenues from contracts with customers and include:

The generation, transmission and distribution of electricity at:

▪ SDG&E

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

The distribution, transportation and storage of natural gas at:

▪ SDG&E

▪ SoCalGas

▪ Sempra Mexico’s Ecogas

Utilities revenues are derived from and recognized upon the delivery of electricity or natural gas services to customers. Amounts that we bill our customers are based on tariffs set by regulators within the respective state or country. For SDG&E and SoCalGas, which follow the provisions of U.S. GAAP governing rate-regulated operations as we discuss in Note 1, amounts that we bill to customers also include adjustments for previously recognized regulatory revenues.

The California Utilities and Ecogas recognize revenues based on regulator-approved revenue requirements, which allows the utilities to recover their reasonable cost of O&M and provides the opportunity to realize their authorized rates of return on their investments. While the California Utilities’ revenues are not affected by actual sales volumes, the pattern of their revenue recognition during the year is affected by seasonality. SoCalGas recognizes annual authorized revenue for core natural gas customers using seasonal factors established in the Triennial Cost Allocation Proceeding. Accordingly, a significant portion of SoCalGas’ annual earnings are recognized in the first and fourth quarters of each year. SDG&E’s authorized revenue recognition is also impacted by seasonal factors, resulting in higher earnings in the third quarter when electric loads are typically higher than in the other three quarters of the year.

SDG&E has an arrangement to provide the California ISO with the ability to control its high voltage transmission lines for prices approved by a regulator. Revenue is recognized over time as access is provided to the California ISO.

Chilquinta Energía and Luz del Sur, our electric distribution utilities in South America, recognize revenues based on tariffs designed to provide for a pass-through to customers of transmission and energy costs, recovery of reasonable O&M based on an efficient model distribution company, incentives to reduce costs and make needed capital investments and a regulated rate of return on the distributor’s regulated asset base.

Factors that can affect the amount, timing and uncertainty of revenues and cash flows include weather, seasonality and timing of customer billings, which may result in unbilled revenues that can vary significantly from month to month and generally approximate one-half month’s deliveries.

The California Utilities recognize revenues from the sale of allocated California GHG emissions allowances at quarterly auctions administered by CARB. GHG allowances are delivered to CARB in advance of the quarterly auctions, and the California Utilities have the right to payment when the GHG allowances are sold at auction. GHG revenue is recognized on a point in time basis within the quarter the auction is held. The California Utilities balance costs and revenues associated with the GHG program through regulatory balancing accounts.

Midstream Revenues

Midstream revenues at Sempra Mexico and Sempra LNG & Midstream typically represent revenues from long-term, U.S. dollar-based contracts with customers for the sale of natural gas and LNG, as well as storage and transportation of natural gas. Invoiced amounts are based on the volume of natural gas delivered and contracted prices.

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

Through its marketing operations, Sempra LNG & Midstream has contracts to sell natural gas and LNG to Sempra Mexico that allow Sempra Mexico to satisfy its obligations under supply agreements with the CFE and other customers, and to supply Sempra Mexico’s TdM power plant. Because Sempra Mexico either immediately delivers the natural gas to its customers or consumes the benefits simultaneously (by using the gas to supply TdM), revenues from Sempra LNG & Midstream’s sale of natural gas to Sempra Mexico are generally recognized over time as delivered. Revenues from LNG sales are recognized at the point when the cargo is delivered to Sempra Mexico.

Revenues from the sale of LNG and natural gas by Sempra LNG & Midstream to Sempra Mexico are adjusted for indemnity payments and profit sharing. We consider these adjustments to be forms of variable consideration that are associated with the sale of LNG and natural gas to Sempra Mexico, and therefore, the related costs have been recorded as an offset to revenues.

We recognize storage revenue from firm capacity reservation agreements, under which we collect a fee for reserving storage capacity for customers in our underground storage facilities. Under these firm agreements, customers pay a monthly fixed reservation fee based on the storage capacity reserved rather than the actual volumes stored. For the fixed-fee component, revenue is recognized on a straight-line basis over the term of the contract. We bill customers for any capacity used in excess of the contracted capacity and such revenues are recognized in the month of occurrence. We also recognize revenue for interruptible storage services. As we discuss in Note 5, on June 25, 2018, our board of directors approved a plan to sell certain of our non-utility natural gas storage assets.

We generate pipeline transportation revenues from firm agreements, under which customers pay a fee for reserving transportation capacity. Revenue is recognized when the volumes are delivered to the customers’ agreed upon delivery point. We recognize revenues for our stand-ready obligation to provide capacity and transportation services throughout the contractual delivery period, as the benefits are received and consumed simultaneously as customers utilize pipeline capacity for the transport and receipt of natural gas and LPG. Invoiced amounts are based on a variable usage fee and a fixed capacity charge, adjusted for the Consumer Price Index, the effects of any foreign currency translation and the actual quantity of commodity transported.

Renewables Revenues

Sempra Renewables and Sempra Mexico develop, invest in and operate solar and wind facilities that have long-term PPAs to sell the electricity and the related green energy attributes they generate to customers, generally load serving entities, and also for Sempra Mexico, industrial and other customers. Load serving entities will sell electric service to their end-users and wholesale customers immediately upon receipt of our power delivery, and industrial and other customers immediately consume the electricity to run their facilities, and thus, we recognize the revenue under the PPAs as the electricity is generated. We invoice customers based on the volume of energy delivered at rates pursuant to the PPAs. As we discuss in Note 5, on June 25, 2018, our board of directors approved a plan to sell our U.S. wind and U.S. solar assets.

Sempra LNG & Midstream has a contractual agreement to provide scheduling and marketing of renewable power for Sempra Renewables. Invoiced amounts are based on a fixed fee per MWh scheduled.

Other Revenues from Contracts with Customers

Tecnored and Tecsur, our energy services companies in South America, generate revenues from the retail sale of electric materials and providing electric construction and infrastructure services to their customers.

TdM is a natural gas-fired power plant that generates revenues from selling electricity and/or resource adequacy to the California ISO and to governmental, public utility and wholesale power marketing entities, as the power is delivered at the interconnection point.

Remaining Performance Obligations

We do not disclose information about remaining performance obligations for (a) contracts with an original expected length of one year or less, (b) revenues recognized at the amount at which we have the right to invoice for services performed, or (c) variable consideration allocated to wholly unsatisfied performance obligations.

For contracts greater than one year, at September 30, 2018, we expected to recognize revenue related to the fixed fee component of the consideration as shown below. SoCalGas did not have any such remaining performance obligations at September 30, 2018.

REMAINING PERFORMANCE OBLIGATIONS (1)
(Dollars in millions)
	Sempra Energy Consolidated	SDG&E
2018	$ 181	$ 1
2019	550	3
2020	544	3
2021	538	3
2022	537	3
Thereafter	3,386	55
Total revenues to be recognized	$ 5,736	$ 68

(1) Excludes intercompany transactions.

Contract Balances from Revenues from Contracts with Customers

From time to time, we receive payments in advance of satisfying the performance obligations associated with customer contracts. We defer such revenues as contract liabilities and recognize them in earnings as the performance obligations are satisfied.

Activities within Sempra Energy’s contract liabilities are presented below. There were no contract liabilities at SDG&E or SoCalGas at September 30, 2018.

CONTRACT LIABILITIES
(Dollars in millions)
Opening balance, January 1, 2018	$ —
Adoption of ASC 606 adjustment	( 68	)
Revenue from performance obligations satisfied during reporting period	23
Payments received in advance	( 25	)
Closing balance, September 30, 2018 (1)	$ ( 70	)

(1) I ncludes $ 6 million in Other Current Liabilities, a negligible amount in Liabilities Held for Sale and $ 64 million in Deferred Credits and Other on the Sempra Energy Condensed Consolidated Balance Sheet.

Receivables from Revenues from Contracts with Customers

The table below shows receivable balances associated with revenues from contracts with customers on our Condensed Consolidated Balance Sheets.

RECEIVABLES FROM REVENUES FROM CONTRACTS WITH CUSTOMERS
(Dollars in millions)
	September 30, 2018	January 1, 2018
Sempra Energy Consolidated:
Accounts receivable – trade, net	$ 1,121	$ 1,194
Accounts receivable – other, net	13	10
Due from unconsolidated affiliates – current (1)	4	8
Assets held for sale	10	—
Total	$ 1,148	$ 1,212
SDG&E:
Accounts receivable – trade, net	$ 470	$ 362
Accounts receivable – other, net	6	3
Due from unconsolidated affiliates – current (1)	3	3
Total	$ 479	$ 368
SoCalGas:
Accounts receivable – trade, net	$ 342	$ 517
Accounts receivable – other, net	7	7
Total	$ 349	$ 524

(1) A mount is presented net of amounts due to unconsolidated affiliates on the Condensed Consolidated Balance Sheets, when right of offset exists.

REVENUES FROM SOURCES OTHER THAN CONTRACTS WITH CUSTOMERS

Certain of our revenues are derived from sources other than contracts with customers and are accounted for under other accounting standards outside the scope of ASC 606.

Utilities Regulatory Revenues

Alternative Revenue Programs

We recognize revenues from alternative revenue programs when the regulator-specified conditions for recognition have been met and adjust these revenues as they are recovered or refunded through future utility service.

Decoupled revenues. As discussed earlier, the regulatory framework requires the California Utilities to recover authorized revenue based on estimated annual demand forecasts approved in regular proceedings before the CPUC. However, actual demand for electricity and natural gas will generally vary from CPUC-approved forecasted demand due to the impacts from weather volatility, energy efficiency programs, rooftop solar and other factors affecting consumption. The CPUC regulatory framework provides for the California Utilities to use a “decoupling” mechanism, which allows the California Utilities to record revenue shortfalls or excess revenues resulting from any difference between actual and forecasted demand to be recovered or refunded in authorized revenue in a subsequent period based on the nature of the account.

Incentive mechanisms. The CPUC applies performance-based measures and incentive mechanisms to all California investor-owned utilities, under which the California Utilities have earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals. Generally, for performance-based awards, if performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties.

Incentive awards are included in revenues when we receive required CPUC approval of the award, the timing of which may not be consistent from year to year. We would record penalties for results below the specified benchmarks against revenues when we believe it is probable that the CPUC would assess a penalty.

Other Cost-Based Regulatory Recovery

The CPUC authorizes the California Utilities to collect revenue requirements for costs that they have been authorized to recover from customers, including the costs to purchase electricity and natural gas, costs associated with administering public purpose, demand response, and customer energy efficiency programs and other programmatic activities authorized as part of the GRC or separately from the GRC. Actual costs are recovered as the commodity or service is delivered, or to the extent actual amounts vary from forecasts, and are generally recovered or refunded within a subsequent period based on the nature of the account through a balancing account mechanism. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred.

Because SDG&E’s and SoCalGas’ cost of electricity and/or natural gas is substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected in the changes in revenues, and therefore do not impact earnings.

The CPUC authorizes balancing accounts for certain programmatic activities. Amounts billed to customers, if any, are recorded in these accounts, as well as actual O&M and applicable capital-related costs (such as depreciation, taxes and ROE). Differences between actual and authorized expenditures are tracked and may be recovered or refunded within a GRC cycle or as part of the subsequent GRC request. Examples of these types of programs include, but are not limited to, gas distribution, gas transmission, and gas storage integrity management. The CPUC may impose various review procedures before authorizing recovery or refund for programs authorized separately from the GRC, including limitations on the total cost of the program, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in disallowances of recovery from ratepayers. Examples of programs subject to reasonableness review procedures include, but are not limited to, PSEP.

We discuss balancing accounts and their effects further in Note 4 below and in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Revenues

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

Sempra Mexico generates lease revenues from operating lease agreements with PEMEX for the use of natural gas and ethane pipelines and LPG storage facilities. Certain PPAs at Sempra Renewables are also accounted for as operating leases. The operating leases have terms ranging from 15 to 25 years.

Sempra LNG & Midstream recognizes other revenues from:

▪ fees related to contractual counterparty obligations for non-delivery of LNG cargoes, as described above.

▪ sales of electricity and natural gas under short-term and long-term contracts and into the spot market and other competitive markets. Revenues include the net realized gains and losses on physical and derivative settlements and net unrealized gains and losses from the change in fair values of the derivatives.

NOTE 4. REGULATORY MATTERS

We discuss regulatory matters in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and provide updates to those discussions and information about new regulatory matters below.

REGULATORY ASSETS AND LIABILITIES

We show the details of regulatory assets and liabilities in the following table.

REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
	September 30, 2018		December 31, 2017
SDG&E:
Fixed-price contracts and other derivatives	$ 47		$ 96
Deferred income taxes refundable in rates	( 267	)	( 281	)
Pension and other postretirement benefit plan obligations	130		153
Removal obligations	( 1,894	)	( 1,846	)
Unamortized loss on reacquired debt	7		9
Environmental costs	28		29
Sunrise Powerlink fire mitigation	119		119
Regulatory balancing accounts (1)
Commodity – electric	23		82
Gas transportation	22		22
Safety and reliability	64		48
Public purpose programs	( 73	)	( 70	)
Other balancing accounts	30		233
Other regulatory liabilities	( 152	)	( 70	)
Total SDG&E	( 1,916	)	( 1,476	)
SoCalGas:
Pension and other postretirement benefit plan obligations	378		513
Employee benefit costs	45		45
Removal obligations	( 868	)	( 924	)
Deferred income taxes refundable in rates	( 383	)	( 437	)
Unamortized loss on reacquired debt	7		8
Environmental costs	24		22
Workers’ compensation	9		12
Regulatory balancing accounts (1)
Commodity – gas, including transportation	139		151
Safety and reliability	312		266
Public purpose programs	( 276	)	( 274	)
Other balancing accounts	( 147	)	( 114	)
Other regulatory liabilities	( 110	)	( 64	)
Total SoCalGas	( 870	)	( 796	)
Sempra Mexico:
Deferred income taxes recoverable in rates	83		83
Other regulatory assets	6		—
Total Sempra Energy Consolidated	$ ( 2,697	)	$ ( 2,189	)

(1) At September 30, 2018 and December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $ 79 million and $ 63 million , respectively. At September 30, 2018 and December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $ 236 million and $ 118 million , respectively.

CALIFORNIA UTILITIES MATTERS

CPUC General Rate Case

The CPUC uses a GRC proceeding to set sufficient rates to allow the California Utilities to recover their reasonable cost of O&M and to provide the opportunity to realize their authorized rates of return on their investment.

2019 General Rate Case

On October 6, 2017, SDG&E and SoCalGas filed their 2019 GRC applications requesting CPUC approval of test year revenue requirements for 2019 and attrition year adjustments for 2020 through 2022. SDG&E and SoCalGas are seeking revenue requirements for 2019 of $ 2.203 billion and $ 2.937 billion , respectively, which is an increase of $ 221 million and $ 481 million

over their respective 2018 revenue requirements (the 2019 proposed and 2018 actual revenue requirements reflect the impact of various updates made during the course of the proceeding). The California Utilities are proposing post-test year revenue requirement annual attrition percentages that are estimated to result in annual increases of approximately 5 percent to 7 percent at SDG&E and approximately 6 percent to 8 percent at SoCalGas. The original GRC applications filed in October 2017 did not reflect the impact of the TCJA, which we discuss in “2016 General Rate Case” below, in Note 1 above and in Note 6 of the Notes to Consolidated Financial Statements in the Annual Report. In April 2018, SDG&E and SoCalGas updated their applications to reflect the impact of the TCJA and filed a joint proposal to address the impacts. The TCJA impact to SDG&E is a reduction of approximately $ 58 million to its 2019 test year revenue requirement; however, SDG&E’s 2019 requested revenue requirement is unchanged as we evaluate potentially higher costs associated with mitigating wildfire risks. The TCJA impact to SoCalGas’ 2019 requested revenue requirement is a reduction of approximately $ 58 million , which is reflected in its updated request.

During the course of the proceeding, Cal PA recommended 2019 revenue requirements of $ 1.918 billion and $ 2.695 billion for SDG&E and SoCalGas, respectively, which is a net decrease of $ 64 million for SDG&E and a net increase of $ 239 million for SoCalGas compared to the 2018 revenue requirements. Cal PA’s proposal reduces the three-year annual attrition percentages to 4 percent for SDG&E and a range of 4 percent to 5 percent for SoCalGas. Cal PA recommends addressing SDG&E’s potential ownership of OMEC in a separate proceeding. As a result, Cal PA’s proposed 2019 revenue requirement does not include the estimated $ 68 million associated with owning and operating the generating facility. SDG&E’s acquisition of OMEC is subject to a CPUC-approved agreement under which the current owner of the facility can exercise a put option at a designated price on or before October 3, 2019, as we discuss in Note 1. TURN and other intervenors oppose various components of our revenue requirement requests in the 2019 GRC applications.

As part of the 2019 GRC, the CPUC reviewed the California Utilities’ interim accountability reports, which compare the authorized and actual spending for certain safety-related activities for 2014 through 2016. In June 2017, SDG&E and SoCalGas filed their first interim accountability reports comparing authorized and actual spending in 2014 and 2015 for certain safety-related activities. Similar data for 2016 was provided with the 2019 GRC application filings in a second interim accountability report filed in October 2017. The stated purpose of the initial interim accountability reports is to provide data and metrics for key safety and risk mitigation areas that will be considered in the 2019 GRC. In October 2018, the CPUC confirmed that the 2014, 2015 and 2016 interim accountability reports were compliant with the requirements and also recommended improvements for subsequent reports.

The results of the rate case may materially and adversely differ from what is contained in the GRC applications.

We expect a final decision from the CPUC in the first half of 2019.

Risk Assessment Mitigation Phase Reporting and Impact on the 2019 GRC Application Filings

In December 2014, the CPUC issued a decision incorporating a risk-based decision-making framework into all future GRC application filings for major natural gas and electric utilities in California. The framework is intended to assist in assessing safety risks and the utilities’ plans to help ensure that such risks are adequately addressed. In advance of filing the California Utilities’ 2019 GRC applications discussed above, two proceedings occurred: the Safety Model Assessment Proceeding and the RAMP. In the Safety Model Assessment Proceeding, the California Utilities demonstrated the models used to prioritize and mitigate risks in order for the CPUC to establish guidelines and standards for these models.

In November 2016, as part of the new framework, SDG&E and SoCalGas filed their first RAMP report presenting a comprehensive assessment of their key safety risks and proposed activities for mitigating such risks. The report details these key safety risks, which include critical operational issues such as natural gas pipeline safety and wildfire safety, and addresses their classification, scoring, mitigation, alternatives, safety culture, quantitative analysis, data collection and lessons learned.

In March 2017, the CPUC’s Safety and Enforcement Division issued its evaluation report providing generally favorable feedback on the California Utilities’ RAMP report, but recommended a more detailed analysis of the risks presented in the report. The new GRC framework does not require the CPUC to adopt the RAMP report. However, SDG&E and SoCalGas included funding requests in their respective 2019 GRC filings for proposed projects or activities outlined in their RAMP reports. In April 2018, the CPUC granted SDG&E’s and SoCalGas’ motion to close the proceeding, as all RAMP procedures have been completed.

Senate Bill 549. In September 2017, SB 549 was signed into law and became effective January 1, 2018. The bill requires that SDG&E and SoCalGas (as electric and gas corporations) annually notify the CPUC when revenue authorized by the CPUC for maintenance, safety or reliability is redirected to other purposes. The CPUC will incorporate this requirement into the accountability reports that are due beginning in December 2018.

2016 General Rate Case

As we discuss in Notes 6 and 14 of the Notes to Consolidated Financial Statements in the Annual Report, the 2016 GRC FD issued by the CPUC in June 2016 required SDG&E and SoCalGas to each establish a two-way income tax expense memorandum account to track revenue variances resulting from certain differences between the income tax expense forecasted in the GRC and the income tax expense incurred from 2016 through 2018. The tracking accounts will remain open until the CPUC decides to close the accounts, which we expect will be reviewed in the 2019 GRC proceedings.

At September 30, 2018 , the recorded regulatory liability associated with these tracked amounts totaled $ 74 million and $ 86 million for SDG&E and SoCalGas, respectively. The recorded liability is primarily related to lower income tax expense incurred than was forecasted in the GRC relating to tax repairs deductions, self-developed software deductions and certain book-over-tax depreciation.

Impacts of the TCJA. As we discuss in Note 1, in the fourth quarter of 2017, we recorded the effect of the remeasurement of our deferred income tax balances at the new federal statutory income tax rate enacted by the TCJA. The remeasurement of deferred income tax balances at SDG&E and SoCalGas resulted in excess deferred income taxes from amounts previously collected from ratepayers at the higher rate. These excess deferred income taxes have been recorded as regulatory liabilities and will be refunded to ratepayers in accordance with the IRC’s normalization provisions and as determined by the CPUC and the FERC. The income tax effects from the TCJA that we recorded in 2017 were provisional. We may adjust our provisional estimates in future reporting periods throughout 2018, and these adjustments may affect regulatory liabilities, the tracking accounts and/or earnings.

The 2016 GRC FD revenue requirement was authorized using a federal income tax rate of 35 percent. As a result of the TCJA, the federal income tax rate became 21 percent effective January 1, 2018. Since SDG&E and SoCalGas continue to collect 2018 authorized revenues based on a 35 percent tax rate, SDG&E and SoCalGas are recording revenue deferrals, aligned with authorized seasonality factors, that reflect the estimated reduction in the 2018 revenue requirement. As of September 30, 2018 , SDG&E and SoCalGas recorded regulatory liabilities of $ 51 million and $ 40 million , respectively, in anticipation of amounts that will benefit customers in future rates. SDG&E also recorded a $ 50 million regulatory liability at September 30, 2018 , relating to its FERC jurisdictional rates, in anticipation of amounts that will benefit customers in future rates for the decrease in the federal income tax rate.

CPUC Cost of Capital

In October 2017, the CPUC approved the embedded cost of debt presented in advice letters filed by SDG&E and SoCalGas, resulting in a revised return on rate base for SDG&E of 7.55 percent and for SoCalGas of 7.34 percent , effective January 1, 2018, as depicted in the table below:

AUTHORIZED COST OF CAPITAL AND RATE STRUCTURE – CPUC
SDG&E				SoCalGas
Authorized weighting	Return on rate base	Weighted return on rate base		Authorized weighting	Return on rate base	Weighted return on rate base
45.25 %	4.59 %	2.08 %	Long-Term Debt	45.60 %	4.33 %	1.97 %
2.75	6.22	0.17	Preferred Stock	2.40	6.00	0.14
52.00	10.20	5.30	Common Equity	52.00	10.05	5.23
100.00 %		7.55 %		100.00 %		7.34 %

The changes to the embedded cost of debt and return on rate base resulting from the updates included in the filed advice letters are summarized below:

CHANGES TO THE EMBEDDED COST OF DEBT
	SDG&E						SoCalGas
	Cost of debt			Return on rate base			Cost of debt			Return on rate base
Previously	5.00		%	7.79		%	5.77		%	8.02		%
Authorized, effective January 1, 2018	4.59		%	7.55		%	4.33		%	7.34		%
Differences	(41	)	bps	(24	)	bps	(144	)	bps	(68	)	bps

The automatic CCM will be in effect to adjust 2019 cost of capital, if necessary. Unless changed by the operation of the CCM, the updated costs of long-term debt and the new ROEs will remain in effect through December 31, 2019. The cost of capital changes will also apply to capital expenditures in 2018 and 2019 for incremental projects not funded through the GRC revenue requirement.

FERC Formulaic Rate Filing

SDG&E submitted its Electric Transmission Owner Formula Rate (TO5) filing with the FERC in October 2018 to be effective January 1, 2019, subject to refund. This proceeding will establish the revenue requirement, including rate of return, for SDG&E’s FERC-regulated electric transmission operations and assets. SDG&E’s TO5 filing proposes to continue most aspects of its existing FERC-authorized formula rate. SDG&E’s TO5 filing is requesting: (1) rates to be determined by a base period of historical costs and a forecast of capital investments, (2) a true-up period, which is similar to a balancing account that is designed to provide SDG&E earnings of no more and no less than its actual cost of service including its authorized return on investment, (3) a true-up of accumulated deferred income tax and (4) a refund of amounts collected in rates in 2018 that presumed a 35 percent federal income tax rate. The net impact of our TO5 filing is a revenue requirement of $ 911 million , an increase in rates of $ 88 million , or 10.6 percent , above 2018’s revenue requirement.

This TO5 proceeding will also set SDG&E’s authorized FERC ROE. SDG&E’s current authorized FERC ROE is 10.05 percent and SDG&E’s TO5 filing proposes a FERC ROE of 11.2 percent . SDG&E expects a decision on its TO5 filing in the second half of 2019.

SEMPRA SOUTH AMERICAN UTILITIES

Luz del Sur serves primarily regulated customers in Peru and revenues are based on rates set by the Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería, or OSINERGMIN). The rates are reviewed and adjusted every four years. OSINERGMIN’s final distribution rate setting resolution for the 2018-2022 period was published on October 16, 2018, and went into effect on November 1, 2018. The resolution decreases the rates Luz del Sur can charge its regulated customers, resulting in a modest reduction in regulated revenues per annum. Luz del Sur will submit a petition for reconsideration to the regulator in November 2018 and expects a response from the regulator by the end of 2018.

Chilquinta Energía serves regulated and unregulated customers in Chile. Distribution revenues and rates are reviewed and set by the National Energy Commission (Comisión Nacional de Energía or CNE) every four years; the most recent review process was completed in November 2016, covering the period from November 2016 through October 2020. On September 28, 2018, a distribution interim rate case, which included an adjustment to rates, was approved to allow adequate recovery of the incremental investment, including the deployment of smart meters to all customers, necessary to comply with the new distribution standards set by the CNE in December 2017. These interim adjusted rates will be applicable from September 28, 2018 through October 2020.

Chilquinta Energía’s most recent review process for zonal transmission rates was completed in September 2017. The final decree approving the rates was published on October 5, 2018. The authorized transmission rates will cover the period from January 2018 through December 2019.

SEMPRA MEXICO

On July 23, 2018, the CRE adjusted Ecogas’ natural gas distribution rates charged to end-users in 2014 through 2016. Ecogas recorded a regulatory asset of $ 7 million for this tariff adjustment, which is recoverable in rates effective September 1, 2018 through December 31, 2020.

NOTE 5. ACQUISITION AND DIVESTITURE ACTIVITY

We consolidate assets acquired and liabilities assumed as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date.

ACQUISITIONS

Sempra Texas Utility

After satisfying all conditions precedent, including final approval from the PUCT, on March 9, 2018, Sempra Energy completed the acquisition of an indirect, 100 -percent interest in Oncor Holdings, which owned 80.03 percent of Oncor, and other EFH assets and liabilities unrelated to Oncor, pursuant to the Merger Agreement with EFH. Oncor is a regulated electric transmission and distribution business that operates the largest transmission and distribution system in Texas. This acquisition expanded our regulated earnings base, while serving as a platform for future growth in the Texas energy market and U.S. Gulf Coast region.

Under the Merger Agreement, we paid Merger Consideration of $ 9.45 billion in cash and an additional $ 31 million representing an adjustment for dividends and payments pursuant to a tax sharing agreement with Oncor and Oncor Holdings. Also on March 9, 2018, in a separate transaction, Sempra Energy, through its interest in Oncor Holdings, acquired an additional 0.22 percent of the outstanding membership interests in Oncor from OMI for approximately $ 26 million in cash, bringing Sempra Energy’s indirect ownership in Oncor to 80.25 percent . TTI, an investment vehicle indirectly owned by third parties unaffiliated with Oncor Holdings or Sempra Energy, continues to own 19.75 percent of Oncor’s outstanding membership interests.

Pursuant to the Merger Agreement, the reorganized EFH (renamed Sempra Texas Holdings Corp.) merged with an indirect subsidiary of Sempra Energy, with Sempra Texas Holdings Corp. continuing as the surviving company and an indirect, wholly owned subsidiary of Sempra Energy. Sempra Texas Holdings Corp. wholly owns EFIH (renamed Sempra Texas Intermediate Holding Company LLC), which holds our 100 -percent interest in Oncor Holdings. Sempra Texas Intermediate Holding Company LLC is included in our newly formed Sempra Texas Utility reportable segment. Other assets and liabilities unrelated to Oncor that were acquired with Sempra Texas Holdings Corp. have been subsumed into our parent organization, Parent and other.

Due to ring-fencing measures, governance mechanisms, and commitments in effect following the Merger, we do not have the power to direct the significant activities of Oncor Holdings and Oncor. Consequently, we account for our 100 -percent ownership interest in Oncor Holdings as an equity method investment. See Note 6 for additional information about our equity method investment in Oncor Holdings and related ring-fencing measures.

The Sempra Texas Utility reportable segment comprises:

The foregoing is a simplified ownership structure that does not show all the subsidiaries of, or other equity interests owned by, these entities.

In anticipation of the Merger, in January 2018, we completed registered public offerings of our common stock (including shares offered pursuant to forward sale agreements), series A preferred stock and long-term debt, as we discuss in Notes 1 and 7 herein and in Note 18 of the Notes to Consolidated Financial Statements in the Annual Report. These offerings provided total initial net

proceeds of approximately $ 7.0 billion for partial funding of the Merger Consideration, of which approximately $ 800 million was used to temporarily pay down commercial paper, pending the closing of the Merger.

On March 8, 2018, to fund a portion of the Merger Consideration, we settled approximately $ 900 million (net of underwriting discounts of $ 16 million ) of forward sales under the forward sale agreements entered into in connection with the public offering of common stock in January 2018 by delivery of 8,556,630 shares of newly issued Sempra Energy common stock, as we discuss in Note 1. We raised the remaining portion of the Merger Consideration through issuances of approximately $ 2.6 billion in commercial paper with a weighted-average maturity of 47 days and a weighted-average interest rate of 2.2 percent per annum.

The total purchase price paid was comprised of the following:

▪ $ 9,450 million of Merger Consideration;

▪ $ 31 million adjustment for dividends and payments pursuant to a tax sharing agreement with Oncor and Oncor Holdings;

▪ $ 26 million paid in a separate transaction to acquire an additional 0.22 percent of the outstanding membership interests in Oncor from OMI; and

▪ $ 59 million of transaction costs included in the basis of our investment in Oncor Holdings.

We accounted for the Merger as an asset acquisition, as the equity method investment in Oncor Holdings represents substantially all of the fair value of the gross assets acquired. The following table sets forth the allocation of the total purchase price paid to the identifiable assets acquired and liabilities assumed.

PURCHASE PRICE ALLOCATION
(Dollars in millions)
	At March 9, 2018
Assets acquired:
Accounts receivable – other, net	$ 1
Due from unconsolidated affiliates	46
Investment in Oncor Holdings	9,161
Deferred income tax assets	353
Other noncurrent assets	109
Total assets acquired	9,670
Liabilities assumed:
Other current liabilities	23
Pension and other postretirement benefit plan obligations	21
Deferred credits and other	60
Total liabilities assumed	104
Net assets acquired	$ 9,566
Total purchase price paid	$ 9,566

The fair value of the equity method investment in Oncor Holdings is primarily attributable to Oncor’s business. Therefore, we considered the underlying assets and liabilities of Oncor when determining the fair value of our equity method investment. As a regulated entity, Oncor’s rates are set and approved by the PUCT, and are designed to recover the cost of providing service and the opportunity to earn a reasonable return on its investments. Accordingly, Oncor applies the guidance under the provisions of U.S. GAAP governing rate-regulated operations. Under U.S. GAAP, regulation is viewed as being a characteristic (restriction) of a regulated entity’s assets and liabilities, and the impact of regulation is considered a fundamental input to measuring the fair value of Oncor’s assets and liabilities. Under this premise, we concluded that the carrying values of all assets and liabilities recoverable through rates are representative of their fair values.

Deferred income tax assets acquired have been recognized based on the facts and circumstances that existed as of the acquisition date related to the resolution of claims in EFH’s emergence from bankruptcy. Should the final resolution of these claims result in a change in deferred income tax assets allocated to us, an adjustment will be made to the purchase price allocation.

Sempra Mexico

On September 26, 2018, Sempra Mexico acquired a 51 -percent interest (with an option to increase its ownership interest to 82.5 percent ) in a subsidiary of Trafigura Mexico, S.A. de C.V. that owns certain permits and land where the Manzanillo Terminal will be built. We consolidate this subsidiary and report NCI for the 49 -percent ownership interest held by Trafigura Mexico, S.A. de C.V. IEnova intends to invest $ 102 million to $ 165 million (depending on ownership interest) to develop, construct and operate

the Manzanillo Terminal, a marine terminal for the receipt, storage and delivery of refined products located in Colima, Mexico. IEnova and Trafigura Mexico, S.A. de C.V. also entered into a long-term, U.S. dollar-denominated terminal services agreement for 50 percent of the terminal’s initial storage capacity of 1.48 million barrels. We expect operations to commence in the fourth quarter of 2020.

On February 28, 2018, Sempra Mexico completed the asset acquisition of Fisterra Midstream Mexico, S. de R.L. de C.V., for a purchase price of $ 5 million . Substantially all of the fair value of the gross assets acquired is attributable to a self-supply permit that allows generators to compete directly with CFE’s retail tariffs and, thus, have access to PPAs with a competitive pricing position. IEnova intends to invest $ 130 million to develop, construct and operate the Don Diego Solar Complex, a 125 -MW solar facility in Sonora, Mexico. IEnova entered into a 15 -year, U.S. dollar-denominated PPA with various subsidiaries of El Puerto de Liverpool, S.A.B. de C.V., for a portion of the capacity. We expect operations to commence in the second half of 2019.

Sempra Renewables

On July 10, 2017, Sempra Renewables paid $ 124 million in cash for an asset acquisition of the Great Valley Solar Project, a portfolio of four solar projects located in Fresno County, California, that were under construction. We placed three of these projects into service in the fourth quarter of 2017 and placed the fourth project into service in April 2018. The portfolio of solar projects is capable of producing up to 200 MW of solar power. The solar projects are fully contracted under four long-term PPAs, with an average contract term of 18 years .

PENDING ACQUISITIONS

Sempra Texas Utility

On October 18, 2018, Oncor entered into the InfraREIT Merger Agreement, whereby Oncor will acquire 100 percent of the issued and outstanding shares of InfraREIT and 100 percent of the limited partnership units of its subsidiary, InfraREIT Partners, for approximately $ 1,275 million , or $ 21 per share and unit, plus approximately $ 40 million for a management agreement termination fee, as well as other customary transaction costs incurred by InfraREIT that will be borne by Oncor as part of the acquisition. In addition, the transaction includes InfraREIT’s outstanding debt, which as of September 30, 2018 was approximately $ 945 million . Consummation of the InfraREIT Merger Agreement is subject to the satisfaction of certain closing conditions, including the substantially concurrent consummation of the transactions contemplated by the Asset Exchange Agreement and Securities Purchase Agreement, discussed below.

On October 18, 2018, Oncor entered into the Asset Exchange Agreement, whereby SDTS will accept and assume certain assets and liabilities of SU in exchange for certain SDTS assets. As currently contemplated, SDTS will receive certain real property and other assets used in the electric transmission and distribution business in Central, North and West Texas, as well as the equity interests in GS Project Entity, L.L.C. (a wholly owned subsidiary of SU) and SU will receive certain real property and other assets that are near the Texas-Mexico border. Immediately prior to completing the exchange, SDTS will become a wholly owned, indirect subsidiary of InfraREIT Partners. Consummation of the Asset Exchange Agreement is subject to the satisfaction of certain closing conditions, including the substantially concurrent consummation of the transactions contemplated by the Securities Purchase Agreement, discussed below.

On October 18, 2018, Sempra Energy entered into the Securities Purchase Agreement, whereby Sempra Texas Utilities Holdings I, LLC (a wholly owned subsidiary of Sempra Energy in our Sempra Texas Utility reportable segment) will acquire a 50 percent economic interest in Sharyland Holdings, LP for approximately $ 98 million , subject to customary closing adjustments. In connection with and prior to the consummation of the Securities Purchase Agreement, Sharyland Holdings, LP will own 100 percent of the membership interests in SU and SU will convert into a limited liability company, which is expected to be named Sharyland Utilities, LLC. Upon consummation of the Securities Purchase Agreement, Sempra Texas Utilities Holdings I, LLC will indirectly own and account for its 50 percent membership interest in Sharyland Utilities, LLC as an equity method investment. Consummation of the Securities Purchase Agreement is subject to the satisfaction of certain closing conditions, including the substantially concurrent consummation of the transactions contemplated by the InfraREIT Merger Agreement and the Asset Exchange Agreement.

For Oncor to fund its acquisition of interests in InfraREIT, Sempra Energy and certain indirect equity holders of TTI have committed to make capital contributions proportionate to Sempra Energy’s and TTI’s respective ownership interests in Oncor, with the amount estimated to be contributed by Sempra Energy equal to approximately $ 1,025 million , excluding Sempra Energy’s share of the approximately $ 40 million for a management agreement termination fee, as well as other customary transaction costs incurred by InfraREIT that will be borne by Oncor as part of the acquisition. We expect to fund our capital contribution to Oncor and to purchase the 50 -percent limited-partner interest in Sharyland Holdings, LP by utilizing a portion of

the anticipated proceeds of $ 1.54 billion (subject to potential customary adjustments) from the pending sale of certain of our non-utility U.S. renewables business to a subsidiary of Con Ed, which we discuss below. The capital contributions are contingent on the satisfaction of customary conditions, including the substantially simultaneous closing of the transactions contemplated by the InfraREIT Merger Agreement, but are not a condition to the transactions contemplated therein.

The transactions contemplated by the agreements discussed above require approval by the PUCT and the FERC and expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, as well as the satisfaction of other regulatory requirements, certain lender consents and other customary closing conditions. In addition, the acquisition of InfraREIT requires the approval of the InfraREIT stockholders, is subject to a standard go shop process whereby InfraREIT can, among other things, solicit offers that may be superior to the terms of the transaction that Oncor has proposed, and the approval by the Committee on Foreign Investment in the United States. We expect that the transactions will close in mid-2019.

Sempra South American Utilities

On June 29, 2018, Chilquinta Energía entered into a sales and purchase agreement with AES Gener S.A. and its subsidiary Sociedad Eléctrica Angamos S.A. to acquire a 100 -percent interest in Compañía Transmisora del Norte Grande S.A. (CTNG). CTNG owns regulated transmission assets in the Valparaiso, Metropolitana and Antofagasta regions of Chile. The fully operating transmission assets include a 114-mile, 110 -kV single-circuit transmission line, an 82-mile, 220 -kV double-circuit transmission line, other transmission assets and substations. CTNG’s regulated revenues are based on tariffs that are set by the CNE and are reviewed by the CNE every four years. This business acquisition is consistent with our long-term growth strategy of owning and operating regulated transmission and distribution assets. We expect to fund the purchase price of approximately $ 220 million , subject to customary adjustments, with available cash on hand at Sempra South American Utilities. The transaction is subject to various closing conditions, including regulatory approval by the Fiscalía Nacional Económica. We expect the transaction to close in the fourth quarter of 2018.

ASSETS HELD FOR SALE

We classify assets as held for sale when management approves and commits to a formal plan to actively market an asset for sale and we expect the sale to close within the next 12 months . Upon classifying an asset as held for sale, we record the asset at the lower of its carrying value or its estimated fair value reduced for selling costs.

Sempra Mexico

Termoeléctrica de Mexicali

In February 2016, management approved a plan to market and sell Sempra Mexico’s TdM, a 625 -MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As a result, we classified TdM as held for sale, stopped depreciating the plant, and have since recorded it each period at the lower of its carrying value or fair value less costs to sell.

On June 1, 2018, management terminated its sales process for TdM due to evolving strategic considerations for projects under development at IEnova. As a result, the assets and liabilities previously classified as held for sale were reclassified as held and used, and depreciation resumed. We reclassified the property, plant and equipment at its carrying value (which approximated fair value) at the date of the subsequent decision not to sell.

Planned Sale of U.S. Renewables and Natural Gas Storage Assets

On June 25, 2018, our board of directors approved a plan to divest certain non-utility natural gas storage assets in the southeast U.S., and all our U.S. wind and U.S. solar assets (collectively, the Assets). The plan to sell the Assets resulted from the most recent comprehensive strategic portfolio review by the board of directors and management. As a result of our plan to sell the Assets, we recorded total impairment charges totaling $ 1.5 billion ( $ 900 million after tax and noncontrolling interests) in June 2018. These charges included $ 1.3 billion ( $ 755 million after tax and noncontrolling interests) at Sempra LNG & Midstream, which is included in Impairment Losses on Sempra Energy’s Condensed Consolidated Statement of Operations, and $ 200 million ( $ 145 million after tax) at Sempra Renewables, which is included in Equity Earnings on Sempra Energy’s Condensed Consolidated Statement of Operations. These impairment charges primarily represent an adjustment of the related assets’ carrying values to estimated fair values, less costs to sell when applicable, which we discuss further in Notes 6 and 9.

Sempra LNG & Midstream

Included in the plan of sale are the following non-utility natural gas storage assets at our Sempra LNG & Midstream reportable segment:

• Mississippi Hub, an underground salt dome with 22 Bcf of working natural gas storage capacity located near Jackson, Mississippi and related compression and pipeline facilities; and

• our 90.9 -percent ownership interest in Bay Gas, a facility located near Mobile, Alabama and related compression and pipeline facilities, that provides underground storage ( 20 Bcf of working natural gas storage capacity) and delivery of natural gas.

Sempra Renewables

Also included in the plan of sale are all wind assets and investments and solar assets and investments, including our wholly owned facilities, joint venture and tax equity investments and projects in development in our Sempra Renewables reportable segment, all of which are located in the U.S.

On September 20, 2018, Sempra Renewables entered into an agreement with a subsidiary of Con Ed to sell, for $ 1.54 billion (subject to potential customary adjustments):

▪ all of its operating solar assets, including assets that are either currently owned through joint ventures or through tax equity arrangements (other than those interests held by tax equity investors);

▪ its solar and battery storage development projects; and

▪ Broken Bow 2 wind generation facility owned through a joint venture.

The pending sale does not include Sempra Renewables’ 50 -percent interests in its other jointly owned wind generation facilities or its tax equity interests in U.S. wind facilities. The transaction is subject to various closing conditions, including approvals from the FERC and the DOE and obtaining consents to replace certain contractual obligations. We expect the transaction to close in the fourth quarter of 2018.

We continue to actively pursue the sale of the remaining Assets, which we expect to complete in 2019.

The carrying amounts of the major classes of assets and related liabilities classified as held for sale associated with Sempra Renewables and Sempra LNG & Midstream are summarized in the following table.

ASSETS HELD FOR SALE AT SEPTEMBER 30, 2018
(Dollars in millions)
	Sempra Renewables	Sempra LNG & Midstream
	U.S. wind and solar assets	Non-utility natural gas storage assets
Cash and cash equivalents	$ 26	$ —
Restricted cash	4	—
Accounts receivable – trade, net	13	4
Accounts receivable – other, net	1	—
Due from unconsolidated affiliates	3	—
Inventories	5	—
Fixed-price contracts and other derivatives, current	1	—
Other current assets	4	6
Property, plant and equipment, net	1,664	143
Fixed-price contracts and other derivatives, noncurrent	2	—
Other noncurrent assets	4	1
Total assets held for sale	$ 1,727	$ 154
Accounts payable – trade	$ 8	$ —
Current portion of long-term debt	7	—
Fixed-price contracts and other derivatives, current (1)	2	—
Other current liabilities	6	5
Long-term debt	63	—
Asset retirement obligations	57	8
Other noncurrent liabilities	2	—
Total liabilities held for sale	$ 145	$ 13

(1) Intercompany activity is eliminated on the Sempra Energy Condensed Consolidated Balance Sheet.

Additionally, Sempra Renewables’ wind and solar equity method investments totaling $ 600 million at September 30, 2018, which are included in the plan of sale, continue to be classified as Other Investments on Sempra Energy’s Condensed Consolidated Balance Sheet, in conformity with U.S. GAAP. See Note 6 for further discussion.

NOTE 6. INVESTMENTS IN UNCONSOLIDATED ENTITIES

Sempra Energy uses the equity method to account for investments in affiliated companies over which we have the ability to exercise significant influence, but not control. Equity earnings and losses, both before and net of income tax, are combined and presented as Equity Earnings on the Condensed Consolidated Statements of Operations. See Note 1 for information regarding the pretax income or loss used to calculate our ETR.

Our equity method investments include various domestic and foreign entities. Our domestic equity method investees are typically partnerships that are pass-through entities for income tax purposes and therefore they do not record income tax. Sempra Energy’s income tax on earnings from these equity method investees, other than Oncor Holdings as we discuss below, is included in Income Tax (Expense) Benefit on the Condensed Consolidated Statements of Operations.

Oncor is a partnership for U.S. federal income tax purposes and is not included in the consolidated income tax return of Sempra Energy. Rather, only our equity earnings from our investment in Oncor Holdings (a disregarded entity for tax purposes) are included in our consolidated income tax return. A tax sharing agreement with TTI, Oncor Holdings and Oncor provides for the calculation of an income tax liability substantially as if Oncor Holdings and Oncor were taxed as corporations, and requires tax payments determined on that basis. While partnerships are not subject to income taxes, in consideration of the tax sharing agreement and Oncor being subject to the provisions of U.S. GAAP governing rate-regulated operations, Oncor recognizes amounts determined under cost-based regulatory rate-setting processes (with such costs including income taxes), as if it were taxed as a corporation. As a result, since Oncor Holdings consolidates Oncor, we recognize equity earnings from our investment in Oncor Holdings net of its recorded income tax.

With the exception of RBS Sempra Commodities, discussed below, our foreign equity method investees are corporations whose operations are taxable on a stand-alone basis in the countries in which they operate, and we recognize our equity in such income or losses net of investee income tax. We may be subject to additional taxes related to these foreign investments, such as taxes on cash dividends or other cash distributions, which are recorded in Income Tax (Expense) Benefit on the Condensed Consolidated Statements of Operations.

We provide additional information concerning our equity method investments in Note 5 above and in Notes 3 and 4 of the Notes to Consolidated Financial Statements in the Annual Report.

SEMPRA TEXAS UTILITY

As we discuss in Note 5, on March 9, 2018, we completed the acquisition of an indirect, 100 -percent interest in Oncor Holdings, which owns an 80.25 -percent interest in Oncor. Due to ring-fencing measures, governance mechanisms, and commitments in effect following the Merger, we do not have the power to direct the significant activities of Oncor Holdings and Oncor, which we discuss in the following paragraph. Consequently, we account for our investment in Oncor Holdings under the equity method, which comprises our Sempra Texas Utility reportable segment.

As we discuss in Note 5, reorganized EFH (renamed Sempra Texas Holdings Corp.) was merged with an indirect subsidiary of Sempra Energy and its assets and liabilities relating to non-Oncor operations have been subsumed into our parent organization. Certain existing ring-fencing measures, governance mechanisms and restrictions remain in effect following the Merger, which are intended to enhance Oncor Holdings’ and Oncor’s separateness from their owners and to mitigate the risk that these entities would be negatively impacted by the bankruptcy of, or other adverse financial developments affecting, EFH or its other subsidiaries or the owners of EFH. Sempra Energy does not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and restrictions limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important corporate issues and actions. These limitations include limited representation on the Oncor Holdings and Oncor boards of directors, as Oncor Holdings and Oncor will continue to have a majority of independent directors. Thus, Oncor Holdings and Oncor will continue to be managed independently (i.e., ring-fenced).

As such, upon consummation of the acquisition, we account for our 100 -percent ownership interest in Oncor Holdings as an equity method investment. The initial fair value of our equity method investment was $ 9,161 million , which includes $ 2,672 million of equity method goodwill related to the excess of purchase price paid over the fair value of the assets and liabilities of Oncor Holdings.

We recognized equity earnings, net of income tax, of $ 154 million and $ 283 million for the three months ended September 30, 2018 and for the period since the acquisition date through September 30, 2018 , respectively. We contributed $ 117 million in cash, commensurate with our ownership interest, to Oncor on April 23, 2018 in accordance with the terms of the Merger Agreement to enable Oncor to achieve its required capital structure calculated for regulatory purposes. We contributed an additional $ 112 million in cash on November 2, 2018.

We provide summarized income statement information for Oncor Holdings in the following table.

SUMMARIZED FINANCIAL INFORMATION – ONCOR HOLDINGS
(Dollars in millions)
	Three months ended September 30, 2018		March 9 - September 30, 2018
Operating revenues	$ 1,095		$ 2,352
Operating expense	( 748	)	( 1,663	)
Income from operations	347		689
Interest expense	( 89	)	( 198	)
Income tax expense	( 53	)	( 105	)
Net income	191		351
Noncontrolling interest held by TTI	( 38	)	( 70	)
Earnings attributable to Sempra Energy (1)	153		281

(1) Earnings at Oncor Holdings differ from earnings at the Sempra Texas Utility segment due to basis differences in AOCI.

SEMPRA SOUTH AMERICAN UTILITIES

In the first quarter of 2017, Sempra South American Utilities recorded the equitization of its $ 19 million note receivable due from Eletrans, resulting in an increase in its investment in this unconsolidated joint venture. Sempra South American Utilities invested cash of $ 1 million in Eletrans in the nine months ended September 30, 2017.

SEMPRA MEXICO

Sempra Mexico invested cash of $ 45 million and $ 72 million in its unconsolidated joint ventures in the nine months ended September 30, 2018 and 2017, respectively.

SEMPRA RENEWABLES

On June 25, 2018, our board of directors approved a plan to sell all wind assets and investments and solar assets and investments, including our wholly owned facilities, joint venture and tax equity investments and projects in development in our Sempra Renewables reportable segment, all of which are located in the U.S. On September 20, 2018, Sempra Renewables entered into an agreement with a subsidiary of Con Ed to sell all of its operating solar assets, including its solar equity method investments, and one wind equity method investment. We discuss the plan of sale and the pending sale agreement with Con Ed in Note 5.

Because of our expectation of a shorter holding period as a result of this plan of sale, we evaluated the recoverability of the carrying amounts of our wind and solar equity method investments and concluded there is an other-than-temporary impairment on certain of our wind equity method investments totaling $ 200 million , which is included in Equity Earnings on Sempra Energy’s Condensed Consolidated Statement of Operations for the nine months ended September 30, 2018. Our wind and solar investments totaling $ 600 million at September 30, 2018, which are also included in the plan of sale, continue to be classified as Other Investments on Sempra Energy’s Condensed Consolidated Balance Sheet, in conformity with U.S. GAAP. We discuss non-recurring fair value measures in Note 9.

SEMPRA LNG & MIDSTREAM

Sempra LNG & Midstream capitalized $ 34 million and $ 36 million of interest in the nine months ended September 30, 2018 and 2017 , respectively, related to its investment in Cameron LNG JV, which has not commenced planned principal operations. In the nine months ended September 30, 2018 and 2017, Sempra LNG & Midstream invested cash of $ 149 million and $ 1 million , respectively, in this unconsolidated joint venture.

RBS SEMPRA COMMODITIES

RBS Sempra Commodities is a United Kingdom limited liability partnership formed by Sempra Energy and RBS in 2008 to own and operate the commodities-marketing businesses previously operated through wholly owned subsidiaries of Sempra Energy. We and RBS sold substantially all of the partnership’s businesses and assets in four separate transactions completed in 2010 and 2011. Since 2011, our investment balance has reflected our share of amounts retained by the partnership to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership, and the distribution of the partnership’s remaining assets, if any. We account for our investment in RBS Sempra Commodities under the equity method.

In September 2018, we fully impaired our remaining equity method investment in RBS Sempra Commodities by recording a charge of $ 65 million in Equity Earnings on Sempra Energy’s Condensed Consolidated Statement of Operations. We discuss matters related to RBS Sempra Commodities further in Note 11.

GUARANTEES

At September 30, 2018 , we had outstanding guarantees aggregating a maximum of $ 4.5 billion with an aggregate carrying value of $ 20 million . We discuss these guarantees in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

NOTE 7. DEBT AND CREDIT FACILITIES

LINES OF CREDIT

On January 17, 2018, pursuant to the terms of the Sempra Energy and Sempra Global credit facilities, the amounts available under the lines of credit were increased by $ 250 million , from $ 1.0 billion to $ 1.25 billion , for Sempra Energy and by $ 850 million , from $ 2.335 billion to $ 3.185 billion , for Sempra Global. At September 30, 2018 , Sempra Energy Consolidated had an aggregate of approximately $ 5.4 billion in three primary committed lines of credit for Sempra Energy, Sempra Global and the California Utilities to provide liquidity and to support commercial paper. The principal terms of these committed lines of credit, which expire in October 2020, are described below and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report. Available unused credit on these lines at September 30, 2018 was approximately $ 3.2 billion . Our foreign operations have additional general purpose credit facilities aggregating $ 1.7 billion , with approximately $ 1.0 billion available unused credit at September 30, 2018 .

PRIMARY U.S. COMMITTED LINES OF CREDIT
(Dollars in millions)
	September 30, 2018
	Total facility		Commercial paper outstanding (1)		Available unused credit
Sempra Energy (2)	$ 1,250		$ —		$ 1,250
Sempra Global (3)	3,185		( 2,147	)	1,038
California Utilities (4) :
SDG&E	750		( 48	)	702
SoCalGas	750		—		750
Less: combined limit of $1 billion for both utilities	( 500	)	—		( 500	)
	1,000		( 48	)	952
Total	$ 5,435		$ ( 2,195	)	$ 3,240

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

(2) The facility also provides for issuance of up to $ 400 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at September 30, 2018.

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

(4) The facility also provides for the issuance of letters of credit on behalf of each utility, subject to a combined letter of credit commitment of $ 250 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. No letters of credit were outstanding at September 30, 2018.

Sempra Energy, SDG&E and SoCalGas must maintain a ratio of indebtedness to total capitalization (as defined in each of the applicable credit facilities) 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 September 30, 2018 .

CREDIT FACILITIES IN SOUTH AMERICA AND MEXICO
(U.S. dollar-equivalent in millions)
		September 30, 2018
	Denominated in	Total facility	Amounts outstanding			Available unused credit
Sempra South American Utilities (1) :
Peru (2)	Peruvian sol	$ 456	$ ( 146	)	(3)	$ 310
Chile	Chilean peso	115	—			115
Sempra Mexico:
IEnova (4)	U.S. dollar	1,170	( 615	)		555
Total		$ 1,741	$ ( 761	)		$ 980

(1) The credit facilities were entered into to finance working capital and for general corporate purposes and expire between 2018 and 2021.

(2) The Peruvian facilities require a debt to equity ratio of no more than 170 percent , with which we were in compliance at September 30, 2018.

(3) Includes bank guarantees of $ 18 million .

(4) Five -year revolver expiring in August 2020 with a syndicate of eight lenders.

Outside of these domestic and foreign committed credit facilities, we have bilateral unsecured letter of credit capacity with select lenders that is uncommitted and supported by reimbursement agreements. At September 30, 2018, we had approximately $ 603 million in letters of credit outstanding under these agreements.

WEIGHTED AVERAGE INTEREST RATES

The weighted average interest rates on total short-term debt at Sempra Energy Consolidated were 2.65 percent and 1.92 percent at September 30, 2018 and December 31, 2017 , respectively. The weighted average interest rates on total short-term debt at SDG&E were 2.35 percent and 1.65 percent at September 30, 2018 and December 31, 2017 , respectively. The weighted average interest rate on total short-term debt at SoCalGas was 1.64 percent at December 31, 2017 .

LONG-TERM DEBT

Sempra Energy

On January 12, 2018, we issued the following debt securities and received net proceeds of $ 4.9 billion (after deducting discounts and debt issuance costs of $ 68 million ):

NOTES ISSUED IN LONG-TERM DEBT OFFERING
(Dollars in millions)
Title of each class of securities	Aggregate principal amount	Maturity	Interest payments
Floating Rate (1) Notes due 2019	$ 500	July 15, 2019	Quarterly
Floating Rate (2) Notes due 2021	700	January 15, 2021	Quarterly
2.400% Senior Notes due 2020	500	February 1, 2020	Semi-annually
2.900% Senior Notes due 2023	500	February 1, 2023	Semi-annually
3.400% Senior Notes due 2028	1,000	February 1, 2028	Semi-annually
3.800% Senior Notes due 2038	1,000	February 1, 2038	Semi-annually
4.000% Senior Notes due 2048	800	February 1, 2048	Semi-annually

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

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

The Floating Rate Notes due 2019 are not subject to redemption at our option. At our option, we may redeem some or all of the Floating Rate Notes due 2021 at any time on or after January 14, 2019 at the applicable redemption price per the terms of the notes. At our option, we may redeem some or all of the fixed rate notes of each series at any time at the applicable redemption price for such series of fixed rate notes.

We used a substantial portion of the net proceeds from this offering to finance a portion of the Merger Consideration and associated transaction costs, as we discuss in Note 5, and approximately $ 800 million to pay down commercial paper.

Ranking

The notes are unsecured and unsubordinated obligations, ranking on a parity in right of payment with all of our other unsecured and unsubordinated indebtedness and guarantees. The notes rank senior to all our existing and future indebtedness, if any, that is subordinated to the notes. The notes are effectively subordinated to any secured indebtedness we have or may incur (to the extent of the collateral securing that indebtedness) and are also effectively subordinated to all indebtedness and other liabilities of our subsidiaries.

SDG&E

On May 17, 2018, SDG&E completed its public offer and sale of $ 400 million of 4.15 -percent, first mortgage bonds maturing in 2048. SDG&E used the proceeds from the offering to repay outstanding commercial paper.

SoCalGas

On May 15, 2018, SoCalGas completed its public offer and sale of $ 400 million of 4.125 -percent, first mortgage bonds maturing in 2048. SoCalGas used the proceeds from the offering to repay outstanding commercial paper.

On September 24, 2018, SoCalGas completed its public offer and sale of $ 550 million of 4.30 -percent, first mortgage bonds maturing in 2049. SoCalGas used the proceeds from the offering to repay outstanding commercial paper and for other general corporate purposes.

Sempra South American Utilities

Luz del Sur drew bank loans in 2018 as follows:

2018 BANK LOAN DRAWS – LUZ DEL SUR
(Dollars in millions)
Month issued	Amount at issuance	Interest rate	Maturity date
June (1)	$ 22	4.32 %	June 2021
July	20	4.96 %	July 2021
September (1)	30	4.30 %	September 2020
September	8	4.40 %	September 2020

(1) Bank loans are included in amounts outstanding under Peruvian credit facilities in the Credit Facilities in South America and Mexico table above.

Sempra Renewables

At September 30, 2018, $ 63 million of long-term debt and $ 7 million of current portion of long-term debt at Sempra Renewables is classified as Liabilities Held for Sale on the Sempra Energy Condensed Consolidated Balance Sheet, as we discuss in Note 5.

INTEREST RATE SWAPS

We discuss our interest rate swaps to hedge cash flows in Note 8.

NOTE 8. DERIVATIVE FINANCIAL INSTRUMENTS

We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk, benchmark interest rate risk and foreign exchange rate exposures. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that our asset values may fall or our liabilities increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not included in the tables below.

In certain cases, we apply the normal purchase or sale exception to derivative instruments and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below.

In all other cases, we record derivatives at fair value on the Condensed Consolidated Balance Sheets. We designate each derivative as (1) a cash flow hedge, (2) a fair value hedge, or (3) undesignated. Depending on the applicability of hedge accounting and, for the California Utilities and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in OCI (cash flow hedge), on the balance sheet (fair value hedges and regulatory offsets), or recognized in earnings. We classify cash flows from the principal settlements of cross-currency swaps that hedge exposure related to Mexican peso-denominated debt as financing activities, and settlements of other derivative instruments as operating activities, on the Condensed Consolidated Statements of Cash Flows.

HEDGE ACCOUNTING

We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that the future cash flows of a given revenue or expense item may vary, and other criteria.

We may designate an interest rate derivative as a fair value hedging instrument if it effectively converts our own debt from a fixed interest rate to a variable rate. The combination of the derivative and debt instrument results in fixing that portion of the fair value of the debt that is related to benchmark interest rates. Designating fair value hedges is dependent on the instrument being used, the effectiveness of the instrument in offsetting changes in the fair value of our debt instruments, and other criteria.

ENERGY DERIVATIVES

Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business, as follows:

▪ The California Utilities use 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 Condensed Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas.

▪ SDG&E is allocated and may purchase CRRs, which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Condensed 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 Condensed Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. Sempra Mexico may also use natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its distribution operations. These derivatives, which are recorded as commodity costs that are offset by regulatory account balances and recovered in rates, are recognized in Cost of Natural Gas on the Condensed Consolidated Statements of Operations.

▪ From time to time, our various businesses, including the California Utilities, may use other energy derivatives to hedge exposures such as the price of vehicle fuel and GHG allowances.

The following table summarizes net energy derivative volumes.

NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
Commodity	Unit of measure	September 30, 2018	December 31, 2017
Sempra Energy Consolidated:
Natural gas	MMBtu	38	46
Electricity	MWh	2	3
Congestion revenue rights	MWh	49	59
SDG&E:
Natural gas	MMBtu	35	39
Electricity	MWh	2	3
Congestion revenue rights	MWh	49	59

In addition to the amounts noted above, we frequently use commodity derivatives to manage risks associated with the physical locations of contractual obligations and assets, such as natural gas purchases and sales.

INTEREST RATE DERIVATIVES

We are exposed to interest rates primarily as a result of our current and expected use of financing. The California Utilities, as well as Sempra Energy and its other subsidiaries and joint ventures, periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We may utilize interest rate swaps, typically designated as fair value hedges, as a means to achieve our targeted level of variable rate debt as a percent of total debt. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings. Separately, Otay Mesa VIE has entered into interest rate swap agreements, designated as cash flow hedges, to moderate its exposure to interest rate changes.

The following table presents the net notional amounts of our interest rate derivatives, excluding joint ventures.

INTEREST RATE DERIVATIVES
(Dollars in millions)
	September 30, 2018		December 31, 2017
	Notional debt	Maturities	Notional debt	Maturities
Sempra Energy Consolidated:
Cash flow hedges (1)	$ 808	2018-2032	$ 861	2018-2032
SDG&E:
Cash flow hedge (1)	287	2018-2019	295	2018-2019

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

FOREIGN CURRENCY DERIVATIVES

We utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and joint ventures. These cash flow hedges exchange our Mexican peso-denominated principal and interest payments into the U.S. dollar and swap Mexican variable interest rates for U.S. fixed interest rates. From time to time, Sempra Mexico and its joint ventures may use other foreign currency derivatives to hedge exposures related to cash flows associated with revenues from contracts denominated in Mexican pesos that are indexed to the U.S. dollar.

We are also exposed to exchange rate movements at our Mexican subsidiaries and joint ventures, which have U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. We utilize foreign currency derivatives as a means to manage the risk of exposure to significant fluctuations in our income tax expense and equity earnings from these impacts, however we generally do not hedge our deferred income tax assets and liabilities or inflation.

In addition, Sempra South American Utilities and its joint ventures may use foreign currency derivatives to manage foreign currency rate risk. We discuss these derivatives at Chilquinta Energía’s Eletrans joint venture investment in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

The following table presents the net notional amounts of our foreign currency derivatives, excluding joint ventures.

FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
	September 30, 2018		December 31, 2017
	Notional amount	Maturities	Notional amount	Maturities
Sempra Energy Consolidated:
Cross-currency swaps	$ 306	2018-2023	$ 408	2018-2023
Other foreign currency derivatives	1,122	2018-2020	345	2018-2019

FINANCIAL STATEMENT PRESENTATION

The Condensed Consolidated Balance Sheets reflect the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Condensed Consolidated Balance Sheets, including the amount of cash collateral receivables that were not offset, as the cash collateral was in excess of liability positions.

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	September 30, 2018
	Current assets: Fixed-price contracts and other derivatives (1)		Other assets: Sundry		Current liabilities: Fixed-price contracts and other derivatives (2)		Deferred credits and other liabilities: Fixed-price contracts and other derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments (3)(4)	$ 1		$ 6		$ ( 7	)	$ ( 125	)
Derivatives not designated as hedging instruments:
Foreign exchange instruments	38		—		—		—
Commodity contracts not subject to rate recovery	93		10		( 95	)	( 9	)
Associated offsetting commodity contracts	( 86	)	( 6	)	86		6
Commodity contracts subject to rate recovery	17		98		( 49	)	( 81	)
Associated offsetting commodity contracts	( 6	)	( 3	)	6		3
Associated offsetting cash collateral	—		—		2		1
Net amounts presented on the balance sheet	57		105		( 57	)	( 205	)
Additional cash collateral for commodity contracts not subject to rate recovery	11		—		—		—
Additional cash collateral for commodity contracts subject to rate recovery	29		—		—		—
Total (5)	$ 97		$ 105		$ ( 57	)	$ ( 205	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments (3)	$ —		$ —		$ ( 4	)	$ —
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	14		98		( 44	)	( 81	)
Associated offsetting commodity contracts	( 6	)	( 3	)	6		3
Associated offsetting cash collateral	—		—		2		1
Net amounts presented on the balance sheet	8		95		( 40	)	( 77	)
Additional cash collateral for commodity contracts subject to rate recovery	26		—		—		—
Total (5)	$ 34		$ 95		$ ( 40	)	$ ( 77	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$ 3		$ —		$ ( 5	)	$ —
Net amounts presented on the balance sheet	3		—		( 5	)	—
Additional cash collateral for commodity contracts subject to rate recovery	3		—		—		—
Total	$ 6		$ —		$ ( 5	)	$ —

(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) Includes $ 1 million of current assets and $ 2 million of noncurrent assets in Assets Held for Sale, as we discuss in Note 5.

(5) Normal purchase contracts previously measured at fair value are excluded.

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31, 2017
	Current assets: Fixed-price contracts and other derivatives (1)		Other assets: Sundry		Current liabilities: Fixed-price contracts and other derivatives (2)		Deferred credits and other liabilities: Fixed-price contracts and other derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments (3)	$ 5		$ 2		$ ( 51	)	$ ( 165	)
Derivatives not designated as hedging instruments:
Foreign exchange instruments	—		—		( 1	)	—
Commodity contracts not subject to rate recovery	81		8		( 72	)	( 6	)
Associated offsetting commodity contracts	( 67	)	( 5	)	67		5
Commodity contracts subject to rate recovery	28		101		( 65	)	( 120	)
Associated offsetting commodity contracts	—		( 1	)	—		1
Associated offsetting cash collateral	—		—		19		4
Net amounts presented on the balance sheet	47		105		( 103	)	( 281	)
Additional cash collateral for commodity contracts not subject to rate recovery	2		—		—		—
Additional cash collateral for commodity contracts subject to rate recovery	17		—		—		—
Total (4)	$ 66		$ 105		$ ( 103	)	$ ( 281	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments (3)	$ —		$ —		$ ( 10	)	$ ( 3	)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	26		101		( 63	)	( 120	)
Associated offsetting commodity contracts	—		( 1	)	—		1
Associated offsetting cash collateral	—		—		19		4
Net amounts presented on the balance sheet	26		100		( 54	)	( 118	)
Additional cash collateral for commodity contracts subject to rate recovery	16		—		—		—
Total (4)	$ 42		$ 100		$ ( 54	)	$ ( 118	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$ 2		$ —		$ ( 2	)	$ —
Net amounts presented on the balance sheet	2		—		( 2	)	—
Additional cash collateral for commodity contracts subject to rate recovery	1		—		—		—
Total	$ 3		$ —		$ ( 2	)	$ —

(1) Included in Current Assets: Other for SoCalGas.

(2) Included in Current Liabilities: Other for SoCalGas.

(3) Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

(4) Normal purchase contracts previously measured at fair value are excluded.

The table below includes the effects of derivative instruments designated as cash flow hedges on the Condensed Consolidated Statements of Operations and in OCI and AOCI:

CASH FLOW HEDGE IMPACTS
(Dollars in millions)
	Pretax gain (loss) recognized in OCI					Pretax gain (loss) reclassified from AOCI into earnings
	Three months ended September 30,					Three months ended September 30,
	2018		2017		Location	2018		2017
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments (1)	$ 16		$ 14		Interest Expense (1)	$ —		$ —
					Other Income, Net	11		—
Interest rate and foreign exchange instruments	20		( 2	)	Equity Earnings	( 3	)	—
Foreign exchange instruments	( 5	)	5		Revenues: Energy- Related Businesses	—		2
Total	$ 31		$ 17			$ 8		$ 2
SDG&E:
Interest rate instruments (1)	$ —		$ —		Interest Expense (1)	$ ( 2	)	$ ( 3	)
	Nine months ended September 30,					Nine months ended September 30,
	2018		2017		Location	2018		2017
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments (1)	$ 57		$ 22		Interest Expense (1)	$ 1		$ 4
					Other Income, Net	11		—
Interest rate and foreign exchange instruments	123		( 57	)	Equity Earnings	( 8	)	( 9	)
Foreign exchange instruments	( 7	)	( 5	)	Revenues: Energy- Related Businesses	1		1
Commodity contracts not subject to rate recovery	—		3		Revenues: Energy- Related Businesses	—		( 9	)
Total	$ 173		$ ( 37	)		$ 5		$ ( 13	)
SDG&E:
Interest rate instruments (1)	$ 1		$ ( 2	)	Interest Expense (1)	$ ( 6	)	$ ( 9	)

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

For Sempra Energy Consolidated, we expect that net gains of $ 15 million , which are net of income tax, that are currently recorded in AOCI (including $ 4 million of losses in NCI related to Otay Mesa VIE at SDG&E) related to cash flow hedges will be reclassified into earnings during the next 12 months as the hedged items affect earnings. SoCalGas expects that $ 1 million of losses, net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next 12 months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts mature.

For all forecasted transactions, the maximum remaining term over which we are hedging exposure to the variability of cash flows at September 30, 2018 is approximately 13 years and 1 year for Sempra Energy Consolidated and SDG&E, respectively. The maximum remaining term for which we are hedging exposure to the variability of cash flows at our equity method investees is 17 years.

The following table summarizes the effects of derivative instruments not designated as hedging instruments on the Condensed Consolidated Statements of Operations.

UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Three months ended September 30,				Nine months ended September 30,
	Location	2018		2017		2018		2017
Sempra Energy Consolidated:
Foreign exchange instruments	Other Income, Net	$ 28		$ 4		$ 35		$ 101
Foreign exchange instruments	Equity Earnings	—		1		—		1
Commodity contracts not subject to rate recovery	Revenues: Energy-Related Businesses	9		( 3	)	—		27
Commodity contracts not subject to rate recovery	Operation and Maintenance	—		—		—		( 1	)
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	62		59		70		36
Commodity contracts subject to rate recovery	Cost of Natural Gas	( 2	)	( 1	)	( 1	)	( 1	)
Total		$ 97		$ 60		$ 104		$ 163
SDG&E:
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	$ 62		$ 59		$ 70		$ 36
SoCalGas:
Commodity contracts not subject to rate recovery	Operation and Maintenance	$ —		$ 1		$ —		$ —
Commodity contracts subject to rate recovery	Cost of Natural Gas	( 2	)	( 1	)	( 1	)	( 1	)
Total		$ ( 2	)	$ —		$ ( 1	)	$ ( 1	)

CONTINGENT FEATURES

For Sempra Energy Consolidated and SDG&E, certain of our derivative instruments contain credit limits which vary depending on our credit ratings. Generally, these provisions, if applicable, may reduce our credit limit if a specified credit rating agency reduces our ratings. In certain cases, if our credit ratings were to fall below investment grade, the counterparty to these derivative liability instruments could request immediate payment or demand immediate and ongoing full collateralization.

For Sempra Energy Consolidated, the total fair value of this group of derivative instruments in a net liability position at September 30, 2018 and December 31, 2017 was $ 3 million and $ 6 million , respectively. At September 30, 2018 , if the credit ratings of Sempra Energy were reduced below investment grade, $ 6 million of additional assets could be required to be posted as collateral for these derivative contracts.

For SDG&E, the total fair value of this group of derivative instruments in a net liability position was $ 1 million at December 31, 2017 .

For Sempra Energy Consolidated, SDG&E and SoCalGas, some of our derivative contracts contain a provision that would permit the counterparty, in certain circumstances, to request adequate assurance of our performance under the contracts. Such additional assurance, if needed, is not material and is not included in the amounts above.

NOTE 9. FAIR VALUE MEASUREMENTS

We discuss the valuation techniques and inputs we use to measure fair value and the definition of the three levels of the fair value hierarchy in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

RECURRING FAIR VALUE MEASURES

The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at September 30, 2018 and December 31, 2017 . We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities, and their placement within the fair value hierarchy. We have not changed the valuation techniques or types of inputs we use to measure recurring fair value during the nine months ended September 30, 2018 .

The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 8 under “Financial Statement Presentation.”

The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests).

Our financial assets and liabilities that were accounted for at fair value on a recurring basis in the tables below include the following (other than a $ 10 million investment at September 30, 2018 measured at net asset value):

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

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

▪ Rabbi Trust investments include marketable securities that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1). These investments in marketable securities were negligible at both September 30, 2018 and December 31, 2017 .

There were no transfers into or out of Level 1, Level 2 or Level 3 for Sempra Energy Consolidated, SDG&E or SoCalGas during the periods presented.

RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Fair value at September 30, 2018
	Level 1		Level 2	Level 3	Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$ 482		$ 4	$ —	$ 486
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	40		10	—	50
Municipal bonds	—		258	—	258
Other securities	—		231	—	231
Total debt securities	40		499	—	539
Total nuclear decommissioning trusts (1)	522		503	—	1,025
Interest rate and foreign exchange instruments (2)	—		45	—	45
Commodity contracts not subject to rate recovery	4		7	—	11
Effect of netting and allocation of collateral (3)	11		—	—	11
Commodity contracts subject to rate recovery	—		5	101	106
Effect of netting and allocation of collateral (3)	24		—	5	29
Total	$ 561		$ 560	$ 106	$ 1,227
Liabilities:
Interest rate and foreign exchange instruments	$ —		$ 132	$ —	$ 132
Commodity contracts not subject to rate recovery	—		12	—	12
Commodity contracts subject to rate recovery	3		5	113	121
Effect of netting and allocation of collateral (3)	( 3	)	—	—	( 3	)
Total	$ —		$ 149	$ 113	$ 262
	Fair value at December 31, 2017
	Level 1		Level 2	Level 3	Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$ 491		$ 5	$ —	$ 496
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	45		9	—	54
Municipal bonds	—		250	—	250
Other securities	—		217	—	217
Total debt securities	45		476	—	521
Total nuclear decommissioning trusts (1)	536		481	—	1,017
Interest rate and foreign exchange instruments	—		7	—	7
Commodity contracts not subject to rate recovery	5		12	—	17
Effect of netting and allocation of collateral (3)	2		—	—	2
Commodity contracts subject to rate recovery	—		2	126	128
Effect of netting and allocation of collateral (3)	12		—	5	17
Total	$ 555		$ 502	$ 131	$ 1,188
Liabilities:
Interest rate and foreign exchange instruments	$ —		$ 217	$ —	$ 217
Commodity contracts not subject to rate recovery	—		6	—	6
Commodity contracts subject to rate recovery	23		7	154	184
Effect of netting and allocation of collateral (3)	( 23	)	—	—	( 23	)
Total	$ —		$ 230	$ 154	$ 384

(1) Excludes cash balances and cash equivalents.

(2) Includes $ 3 million of interest rate instruments classified as Assets Held for Sale, as we discuss in Note 5.

(3) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
	Fair value at September 30, 2018
	Level 1		Level 2	Level 3	Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$ 482		$ 4	$ —	$ 486
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	40		10	—	50
Municipal bonds	—		258	—	258
Other securities	—		231	—	231
Total debt securities	40		499	—	539
Total nuclear decommissioning trusts (1)	522		503	—	1,025
Commodity contracts subject to rate recovery	—		2	101	103
Effect of netting and allocation of collateral (2)	21		—	5	26
Total	$ 543		$ 505	$ 106	$ 1,154
Liabilities:
Interest rate instruments	$ —		$ 4	$ —	$ 4
Commodity contracts subject to rate recovery	3		—	113	116
Effect of netting and allocation of collateral (2)	( 3	)	—	—	( 3	)
Total	$ —		$ 4	$ 113	$ 117
	Fair value at December 31, 2017
	Level 1		Level 2	Level 3	Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$ 491		$ 5	$ —	$ 496
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	45		9	—	54
Municipal bonds	—		250	—	250
Other securities	—		217	—	217
Total debt securities	45		476	—	521
Total nuclear decommissioning trusts (1)	536		481	—	1,017
Commodity contracts subject to rate recovery	—		—	126	126
Effect of netting and allocation of collateral (2)	11		—	5	16
Total	$ 547		$ 481	$ 131	$ 1,159
Liabilities:
Interest rate instruments	$ —		$ 13	$ —	$ 13
Commodity contracts subject to rate recovery	23		5	154	182
Effect of netting and allocation of collateral (2)	( 23	)	—	—	( 23	)
Total	$ —		$ 18	$ 154	$ 172

(1) Excludes cash balances and cash equivalents.

(2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
	Fair value at September 30, 2018
	Level 1	Level 2	Level 3	Total
Assets:
Commodity contracts subject to rate recovery	$ —	$ 3	$ —	$ 3
Effect of netting and allocation of collateral (1)	3	—	—	3
Total	$ 3	$ 3	$ —	$ 6
Liabilities:
Commodity contracts subject to rate recovery	$ —	$ 5	$ —	$ 5
Total	$ —	$ 5	$ —	$ 5
	Fair value at December 31, 2017
	Level 1	Level 2	Level 3	Total
Assets:
Commodity contracts subject to rate recovery	$ —	$ 2	$ —	$ 2
Effect of netting and allocation of collateral (1)	1	—	—	1
Total	$ 1	$ 2	$ —	$ 3
Liabilities:
Commodity contracts subject to rate recovery	$ —	$ 2	$ —	$ 2
Total	$ —	$ 2	$ —	$ 2

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

Level 3 Information

T he following table sets forth reconciliations of changes in the fair value of CRRs and long-term, fixed-price electricity positions classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E.

LEVEL 3 RECONCILIATIONS (1)
(Dollars in millions)
	Three months ended September 30,
	2018		2017
Balance at July 1	$ ( 31	)	$ ( 90	)
Realized and unrealized gains	6		30
Settlements	13		23
Balance at September 30	$ ( 12	)	$ ( 37	)
Change in unrealized gains (losses) relating to instruments still held at September 30	$ 6		$ 38
	Nine months ended September 30,
	2018		2017
Balance at January 1	$ ( 28	)	$ ( 74	)
Realized and unrealized gains	21		14
Allocated transmission instruments	3		—
Settlements	( 8	)	23
Balance at September 30	$ ( 12	)	$ ( 37	)
Change in unrealized gains (losses) relating to instruments still held at September 30	$ —		$ 26

(1) Excludes the effect of the contractual ability to settle contracts under master netting agreements.

SDG&E’s Energy and Fuel Procurement department, in conjunction with SDG&E’s finance group, is responsible for determining the appropriate fair value methodologies used to value and classify CRRs and long-term, fixed-price electricity positions on an ongoing basis. Inputs used to determine the fair value of CRRs and fixed-price electricity positions are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to these instruments to be recoverable through customer rates. As such, there is no impact to earnings from changes in the fair value of these instruments.

CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California ISO, an objective source. Annual auction prices are published once a year, typically in the middle of November, and are the basis for valuing CRRs settling in the following year. For the CRRs settling from January 1 to December 31, the auction price inputs, at a given location, were in the following ranges for the years indicated below:

CONGESTION REVENUE RIGHTS AUCTION PRICE INPUTS — Settlement year	Price per MWh
2018	$ ( 7.25	)	to	$ 11.99
2017	( 11.88	)	to	6.93

The impact associated with discounting is negligible. Because these auction prices are a less observable input, these instruments are classified as Level 3. The fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 8.

Long-term, fixed-price electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs. These inputs range from $ 20.40 per MWh to $ 59.85 per MWh at September 30, 2018 , and $ 21.35 per MWh to $ 48.97 per MWh at September 30, 2017 . A significant increase or decrease in market electricity forward prices would result in a significantly higher or lower fair value, respectively. We summarize long-term, fixed-price electricity position volumes in Note 8.

Realized gains and losses associated with CRRs and long-term electricity positions, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations. Unrealized gains and losses are recorded as regulatory assets and liabilities and therefore do not affect earnings.

Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, accounts and notes receivable, short-term amounts due to/from unconsolidated affiliates, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Condensed Consolidated Balance Sheets:

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
	September 30, 2018
	Carrying amount	Fair value
		Level 1	Level 2	Level 3	Total
Sempra Energy Consolidated:
Long-term amounts due from unconsolidated affiliates (1)	$ 626	$ —	$ 599	$ 40	$ 639
Long-term amounts due to unconsolidated affiliates (2)	35	—	32	—	32
Total long-term debt (3)(4)(5)	22,207	738	20,791	487	22,016
SDG&E:
Total long-term debt (5)(6)	$ 5,064	$ —	$ 4,902	$ 287	$ 5,189
SoCalGas:
Total long-term debt (7)	$ 3,459	$ —	$ 3,474	$ —	$ 3,474
	December 31, 2017
	Carrying amount	Fair value
		Level 1	Level 2	Level 3	Total
Sempra Energy Consolidated:
Long-term amounts due from unconsolidated affiliates (1)	$ 604	$ —	$ 528	$ 96	$ 624
Long-term amounts due to unconsolidated affiliates (2)	35	—	32	—	32
Total long-term debt (4)(5)	17,138	817	17,134	458	18,409
SDG&E:
Total long-term debt (5)(6)	$ 4,868	$ —	$ 5,073	$ 295	$ 5,368
SoCalGas:
Total long-term debt (7)	$ 3,009	$ —	$ 3,192	$ —	$ 3,192

(1) Excludes accumulated interest outstanding of $ 66 million and $ 29 million at September 30, 2018 and December 31, 2017 , respectively, and excludes foreign currency translation losses of $ 10 million and $ 35 million on a Mexican peso-denominated loan at September 30, 2018 and December 31, 2017 , respectively.

(2) Excludes accumulated interest of $ 1 million outstanding at September 30, 2018 and negligible interest outstanding at December 31, 2017 .

(3) Includes $ 70 million of long-term debt classified as Liabilities Held for Sale, as we discuss in Notes 5 and 7.

(4) Before reductions for unamortized discount (net of premium) and debt issuance costs of $ 211 million and $ 143 million at September 30, 2018 and December 31, 2017 , respectively, and excludes build-to-suit and capital lease obligations of $ 873 million and $ 877 million at September 30, 2018 and December 31, 2017 , respectively. We discuss our long-term debt in Note 7 above and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.

(5) Level 3 instruments include $ 287 million and $ 295 million at September 30, 2018 and December 31, 2017 , respectively, related to Otay Mesa VIE.

(6) Before reductions for unamortized discount and debt issuance costs of $ 49 million and $ 45 million at September 30, 2018 and December 31, 2017 , respectively, and excludes capital lease obligations of $ 725 million and $ 732 million at September 30, 2018 and December 31, 2017 , respectively.

(7) Before reductions for unamortized discount and debt issuance costs of $ 33 million and $ 24 million at September 30, 2018 and December 31, 2017 , respectively, and excludes capital lease obligations of $ 4 million and $ 1 million at September 30, 2018 and December 31, 2017 , respectively.

We provide the fair values for the securities held in the NDT related to SONGS in Note 10.

NON-RECURRING FAIR VALUE MEASURES

Sempra Renewables

U.S. Wind Investments

As we discuss in Notes 5 and 6, on June 25, 2018, our board of directors approved a plan to sell all our wind and solar equity method investments at Sempra Renewables. Because of our expectation of a shorter holding period as a result of this plan of sale, we evaluated the recoverability of the carrying amounts of each of these investments and concluded there is an other-than-temporary impairment on certain of our wind equity method investments totaling $ 200 million ( $ 145 million after tax), which we recorded in Equity Earnings on Sempra Energy’s Condensed Consolidated Statement of Operations for the nine months ended September 30, 2018. We measured the estimated fair value of $ 145 million at June 25, 2018 using a discounted cash flow model including significant unobservable inputs, adjusted for our applicable ownership percentages, which is a Level 3 measurement in the fair value hierarchy. The key inputs to the methodology were contracted and merchant pricing, and the discount rate .

Sempra LNG & Midstream

Non-Utility Natural Gas Storage Assets

As we discuss in Note 5, on June 25, 2018, our board of directors approved a plan to sell Mississippi Hub and our 90.9 -percent ownership interest in Bay Gas (the non-utility natural gas storage assets). We also own other U.S. midstream assets that are not included in the plan of sale and primarily include our 75.4 -percent interest in LA Storage, a salt cavern development project in Cameron Parish, Louisiana. The LA Storage project also includes an existing 23.3-mile pipeline header system that is not currently contracted.

Because of the plan of sale, we considered a market participant’s view of the total value of the non-utility natural gas storage assets and determined that their fair value, less costs to sell, may be less than their carrying value. Additionally, our inability to secure customer contracts that would support further investment in LA Storage has led us to assess and conclude that the full carrying value of these other U.S. midstream assets may not be recoverable. As a result, we recorded an impairment of $ 1.3 billion ( $ 755 million after tax and noncontrolling interest) in Impairment Losses on Sempra Energy’s Condensed Consolidated Statement of Operations for the nine months ended September 30, 2018.

We measured the estimated fair value of $ 190 million at June 25, 2018 using a discounted cash flow approach. This approach included unobservable inputs, resulting in a Level 3 measurement in the fair value hierarchy. We considered a market participant’s view of the values of the non-utility natural gas storage assets based on an estimation of future net cash flows. To estimate future net cash flows, we considered the non-utility natural gas storage assets’ prospects for generating revenues and cash flows beyond their existing contracted capacity and tenors, including natural gas price volatility and seasonality factors, as well as discount rates commensurate with the risks inherent in the cash flows.

The following table summarizes significant inputs that impacted our non-recurring fair value measures.

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED	Estimated fair value (in millions)		Valuation technique	Fair value hierarchy	% of fair value measurement	Inputs used to develop measurement	Range of inputs
Certain of our U.S. wind equity method investments	$ 145	(1)	Discounted cash flows	Level 3	100 %	Contracted and observable merchant prices per MWh	$29 - $92	(2)
						Discount rate	8% - 10%	(3)
Non-utility natural gas storage assets	$ 190	(4)	Discounted cash flows	Level 3	100 %	Storage rates per Dth/month	$0.06 - $0.22	(2)
						Discount rate	10%	(3)

(1) At measurement date of June 25, 2018. At September 30, 2018 , these U.S. wind equity method investments had a carrying value of $ 136 million reflecting subsequent business activity.

(2) Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.

(3) An increase in the discount rate would result in a decrease in fair value.

(4) At measurement date of June 25, 2018. At September 30, 2018 , Mississippi Hub and Bay Gas were classified as held for sale and had a net carrying value of $ 141 million , reflecting subsequent business activity and estimated costs to sell, as we discuss in Note 5. Our other U.S. midstream assets that were measured at fair value, including LA Storage, continue to be classified as property, plant and equipment and had a net carrying value of $ 32 million at September 30, 2018 .

NOTE 10. SAN ONOFRE NUCLEAR GENERATING STATION

We provide below updates to ongoing matters related to SONGS, a nuclear generating facility near San Clemente, California that ceased operations in June 2013, and in which SDG&E has a 20 -percent ownership interest. We discuss SONGS further in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

SONGS STEAM GENERATOR REPLACEMENT PROJECT

As part of the SGRP, the steam generators were replaced in SONGS Units 2 and 3, and the Units returned to service in 2010 and 2011, respectively. Both Units were shut down in early 2012 after a water leak occurred in the Unit 3 steam generator. Edison concluded that the leak was due to unexpected wear from tube-to-tube contact. At the time the leak was identified, Edison also inspected and tested Unit 2 and subsequently found unexpected tube wear in Unit 2’s steam generator. These issues with the steam generators ultimately resulted in Edison’s decision to permanently retire SONGS.

The replacement steam generators were designed and provided by MHI. In 2013, Edison instituted arbitration proceedings against MHI seeking recovery of damages. The other SONGS co-owners, SDG&E and the City of Riverside, participated as claimants and respondents. On March 13, 2017, the International Chamber of Commerce International Court of Arbitration Tribunal (the Tribunal) overseeing the arbitration found MHI liable for breach of contract, subject to a contractual limitation of liability, and rejected the claimants’ other claims. The Tribunal awarded $ 118 million in damages to the SONGS co-owners, but determined that MHI was the prevailing party and awarded it 95 percent of its arbitration costs. The damage award was offset by these costs, resulting in a net award of approximately $ 60 million in favor of the SONGS co-owners. SDG&E’s specific allocation of the damage award was $ 24 million reduced by costs awarded to MHI of approximately $ 12 million , resulting in a net damage award of $ 12 million , which was paid by MHI to SDG&E in March 2017. In accordance with the Amended Settlement Agreement discussed below, SDG&E recorded the proceeds from the MHI arbitration by reducing O&M for previously incurred legal costs of $ 11 million , and shared the remaining $ 1 million equally between ratepayers and shareholders.

SETTLEMENT AGREEMENT TO RESOLVE THE CPUC’S ORDER INSTITUTING INVESTIGATION INTO THE SONGS OUTAGE

In 2012, in response to the SONGS outage, the CPUC issued the SONGS OII, which was intended to determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of this outage.

In November 2014, the CPUC issued a final decision approving an Amended Settlement Agreement in the SONGS OII proceeding. We describe the terms and provisions of the Amended Settlement Agreement in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

In May 2016, following the filing of petitions for modification by various parties, the CPUC issued a procedural ruling reopening the record of the OII to address the issue of whether the Amended Settlement Agreement is reasonable and in the public interest.

In December 2016, the CPUC issued another procedural ruling directing parties to the SONGS OII to determine whether an agreement could be reached to modify the Amended Settlement Agreement previously approved by the CPUC, to resolve allegations that unreported ex parte communications between Edison and the CPUC resulted in an unfair advantage at the time the settlement agreement was negotiated.

On January 30, 2018, SDG&E, Edison, Cal PA, TURN and other intervenors entered into a settlement agreement (the Revised Settlement Agreement). On the same date, a Joint Motion for Adoption of the Settlement Agreement was filed with the CPUC. The Revised Settlement Agreement resolves all issues under consideration in the SONGS OII and modifies the Amended Settlement Agreement. The Revised Settlement Agreement was the result of multiple mediation sessions in 2017 and January 2018 and was signed following a settlement conference in the SONGS OII, as required under CPUC rules. In February 2018, the parties filed a motion to stay the proceedings in the OII pending the CPUC’s consideration of the Revised Settlement Agreement. In February and March of 2018, the CPUC granted the parties’ request and established a procedural schedule for 2018 that includes additional testimony, a status conference and briefing, and public participation and evidentiary hearings in April through July.

On July 26, 2018, the CPUC issued a final decision approving the Revised Settlement Agreement with only one modification: removal of the GHG emissions reduction research program that was to be funded by utility shareholders over a five-year period in the amount of $ 12.5 million , of which $ 2.5 million was SDG&E’s share. On August 2, 2018, parties to the Revised Settlement Agreement submitted a notice that they accept the settlement agreement, as modified.

In connection with the Revised Settlement Agreement, and in exchange for the release of certain SONGS-related claims, SDG&E and Edison entered into the Utility Shareholder Agreement, described below, in which Edison has agreed to pay for the amounts that SDG&E would have received in rates under the Amended Settlement Agreement but will not receive upon implementation of the Revised Settlement Agreement.

Disallowances, Refunds and Recoveries

Under the Revised Settlement Agreement, SDG&E and Edison ceased rate recovery of SONGS costs as authorized under the Amended Settlement Agreement as of December 19, 2017, when the present value of their combined remaining SONGS regulatory assets equaled $ 775 million , of which $ 152 million represents SDG&E’s share. Under the Utility Shareholder Agreement, Edison is obligated to pay SDG&E the full amount of SDG&E’s revenue requirement not recovered from ratepayers, as described below. SDG&E began refunding to customers SONGS-related amounts recovered in rates after December 19, 2017 on October 1, 2018.

Utility Shareholder Agreement

On January 10, 2018, SDG&E and Edison entered into the Utility Shareholder Agreement. Under the terms of the Utility Shareholder Agreement, Edison has an obligation to compensate SDG&E for the revenue requirement amounts that SDG&E will no longer recover because of the Revised Settlement Agreement. In exchange for Edison’s reimbursement, the parties mutually released each other from the “SONGS Issues,” a defined term that consists of 18 broad categories. The effect of the agreement is that the parties released each other from any and all claims that each party had or could have asserted related to the steam generator replacement failure and its aftermath. The Utility Shareholder Agreement became effective upon CPUC approval of the Revised Settlement Agreement. Edison’s payment obligation commenced on October 30, 2018, and amounts are due to SDG&E quarterly thereafter until April 2022, which approximates the amounts and timing of amounts of what would have been SDG&E’s recoveries from ratepayers contemplated under the Amended Settlement Agreement.

Accounting and Financial Impacts

As a result of the Revised Settlement Agreement by the settling parties and the Utility Shareholder Agreement, at September 30, 2018 , SDG&E has a receivable from Edison, including accrued interest, totaling $ 152 million , with $ 59 million classified as current and $ 93 million classified as noncurrent. This receivable reflects amounts Edison is obligated to pay to SDG&E in lieu of amounts SDG&E would have collected from ratepayers associated with the SONGS regulatory asset.

NUCLEAR DECOMMISSIONING AND FUNDING

As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be done once Units 2 and 3 are dismantled. Edison contracted with a joint venture of AECOM and EnergySolutions (known as SONGS Decommissioning Solutions) as the general contractor to complete the dismantlement of SONGS. The majority of the dismantlement work is expected to take 10 years . SDG&E is responsible for approximately 20 percent of the total contract price.

In accordance with state and federal requirements and regulations, SDG&E has assets held in the NDT to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. The amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the NDT are invested in accordance with CPUC regulations. The NDT assets are presented on the Sempra Energy and SDG&E Condensed Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.

In March 2018, SDG&E and Edison jointly filed an application requesting CPUC approval of revised remaining decommissioning cost estimates (for costs estimated to be incurred in 2018 and beyond) for SONGS Unit 1 of $ 207 million (in 2014 dollars), of which SDG&E’s share is $ 41 million , and SONGS Units 2 and 3 of $ 3.2 billion (in 2014 dollars), of which SDG&E’s share is $ 638 million . In addition, SDG&E has estimated internal decommissioning costs (for costs estimated to be incurred in 2018 and beyond) of $ 3 million (in 2014 dollars) for SONGS Unit 1 and $ 43 million (in 2014 dollars) for SONGS Units 2 and 3. We expect a ruling by the CPUC on the joint application in 2019. Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. SDG&E has received authorization from the CPUC to access NDT funds of up to $ 362 million for 2013 through 2018 (2018 forecasted) SONGS decommissioning costs. This includes up to $ 60 million authorized by the CPUC in January 2018 to be withdrawn from the NDT for forecasted 2018 SONGS Units 2 and 3 costs as decommissioning costs are incurred.

In December 2016, the IRS and the U.S. Department of the Treasury issued proposed regulations that clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified trust fund. The proposed regulations state that costs related to the construction and maintenance of independent spent fuel management installations are included in the definition of “nuclear decommissioning costs.” The proposed regulations will be effective prospectively once they are finalized; however, the IRS has stated that it will not challenge taxpayer positions consistent with the proposed regulations for taxable years ending on or after the date the proposed regulations were issued. SDG&E is awaiting the adoption of, or additional

refinement to, the proposed regulations before determining whether the proposed regulations will allow SDG&E to access the NDT funds for reimbursement or payment of the spent fuel management costs incurred in 2017 and subsequent years. Further clarification of the proposed regulations could enable SDG&E to access the NDT to recover spent fuel management costs before Edison reaches final settlement with the DOE regarding the DOE’s reimbursement of these costs. Historically, the DOE’s reimbursements of spent fuel storage costs have not resulted in timely or complete recovery of these costs. We discuss the DOE’s responsibility for spent nuclear fuel below. The IRS held public hearings on the proposed regulations in October 2017. It is unclear when clarification of the proposed regulations might be provided or when the proposed regulations will be finalized.

The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT. We provide additional fair value disclosures for the NDT in Note 9.

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost	Gross unrealized gains	Gross unrealized losses		Estimated fair value
At September 30, 2018:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies (1)	$ 51	$ —	$ ( 1	)	$ 50
Municipal bonds (2)	259	2	( 3	)	258
Other securities (3)	233	1	( 3	)	231
Total debt securities	543	3	( 7	)	539
Equity securities	166	324	( 4	)	486
Cash and cash equivalents	17	—	—		17
Total	$ 726	$ 327	$ ( 11	)	$ 1,042
At December 31, 2017:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	$ 54	$ —	$ —		$ 54
Municipal bonds	245	7	( 2	)	250
Other securities	215	3	( 1	)	217
Total debt securities	514	10	( 3	)	521
Equity securities	171	326	( 1	)	496
Cash and cash equivalents	16	—	—		16
Total	$ 701	$ 336	$ ( 4	)	$ 1,033

(1) Maturity dates are 2019-2048.

(2) Maturity dates are 2018-2056.

(3) Maturity dates are 2018-2064.

The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales.

SALES OF SECURITIES IN THE NDT
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
Proceeds from sales	$ 216		$ 259		$ 703		$ 1,082
Gross realized gains	3		8		32		132
Gross realized losses	( 1	)	( 3	)	( 6	)	( 11	)

Net unrealized gains and losses, as well as realized gains and losses that are reinvested in the NDT, are included in noncurrent Regulatory Liabilities on Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.

U.S. DEPARTMENT OF ENERGY NUCLEAR FUEL DISPOSAL

Spent nuclear fuel from SONGS is currently stored on-site in an ISFSI licensed by the NRC or temporarily in spent fuel pools. In October 2015, the California Coastal Commission approved Edison’s application for the proposed expansion of the ISFSI at SONGS. The ISFSI expansion began construction in 2016 and is expected to be fully loaded with spent fuel in 2019 and to operate until 2049, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS.

The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. SDG&E will continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel. In April 2016, Edison executed a spent fuel settlement agreement with the DOE for $ 162 million covering damages incurred from 2006 through 2013. In May 2016, Edison refunded SDG&E $ 32 million for its respective share of the damage award paid. In applying this refund, SDG&E recorded a $ 23 million reduction to the SONGS regulatory asset, an $ 8 million reduction of its nuclear decommissioning balancing account and a $ 1 million reduction in its SONGS O&M cost balancing account.

In September 2016, Edison filed claims with the DOE for $ 56 million in spent fuel management costs incurred in 2014 and 2015 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. In February 2017, the DOE reduced the request to approximately $ 43 million primarily due to reductions to the claimed fuel canister costs. SDG&E received its $ 9 million respective share of the claim from Edison in May 2017 and recorded the proceeds in balancing accounts or as reductions to regulatory assets for the benefit of ratepayers.

In October 2017, Edison filed claims with the DOE for $ 58 million in spent fuel management costs incurred in 2016 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. SDG&E’s respective share of the claim is $ 12 million . In March 2018, the DOE issued its determination of allowable costs for the claim as $ 44 million , with SDG&E’s respective share as $ 9 million . In April 2018, Edison requested reconsideration from the DOE of $ 1 million of the DOE’s deductions from the claimed amount. In May 2018, the DOE issued a supplemental determination that the $ 1 million requested for reconsideration is allowable and should be reimbursed. In July 2018, SDG&E received its $ 9 million total share of the 2016 claim.

The 2016 spent fuel settlement agreement governs the submission of claims for costs incurred through December 31, 2016. It is unclear whether Edison will enter into a new settlement with the DOE or pursue litigation claims for spent fuel management costs incurred on or after January 1, 2017.

NUCLEAR INSURANCE

Edison requested and was granted approval in January 2018 by the NRC to reduce the nuclear liability and property damage insurance requirement. However, these changes in SONGS nuclear insurance levels require approval from all SONGS owners, as described below.

SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. Currently, this insurance provides $ 450 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides an additional $ 110 million of coverage. If a nuclear liability loss occurs at SONGS and exceeds the $ 450 million insurance limit, this additional coverage would be available to provide a total of $ 560 million in coverage limits per incident. The SFP is a program that provides additional insurance. If a nuclear liability loss occurs at any U.S. licensed/commercial reactor and exceeds the $ 450 million insurance, all SFP participants would be required to contribute to the SFP. Effective January 5, 2018, the NRC approved Edison’s request to reduce the nuclear liability insurance requirement from $ 450 million to $ 100 million and withdraw from participation in the SFP for SONGS. On April 5, 2018, the SONGS co-owners approved withdrawing from participation in the SFP for SONGS, but maintaining the nuclear liability insurance coverage at current levels ( $ 450 million ). Confirmation of SONGS’ withdrawal from the SFP has been received and became effective January 5, 2018.

The SONGS owners, including SDG&E, also maintain nuclear property damage insurance that exceeds the minimum federal requirements of $ 1.06 billion . This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $ 10.4 million of retrospective premiums based on overall member claims. All of SONGS’ insurance claims arising out of the failures of the MHI replacement steam generators have been settled with NEIL. Effective January 10, 2018, the NRC approved Edison’s request to reduce its minimum property damage insurance requirement for SONGS from $ 1.06 billion to $ 50 million . However, on April 5,

2018, the SONGS co-owners approved maintaining its current property damage insurance at $ 1.5 billion , but with a new $ 500 million property damage sublimit on the ISFSI.

The nuclear property insurance program includes an industry aggregate loss limit for non-certified acts of terrorism (as defined by the Terrorism Risk Insurance Act) of $ 3.24 billion . This is the maximum amount that will be paid to insured members who suffer losses or damages from these non-certified terrorist acts.

NOTE 11. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to reasonably estimate the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed applicable insurance coverage and could materially adversely affect our business, cash flows, results of operations, financial condition and prospects. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.

At September 30, 2018 , loss contingency accruals for legal matters, including associated legal fees, that are probable and estimable were $ 230 million for Sempra Energy Consolidated, including $ 3 million for SDG&E and $ 176 million for SoCalGas. Amounts for Sempra Energy and SoCalGas include $ 127 million for matters related to the Aliso Canyon natural gas storage facility gas leak, which we discuss below.

SDG&E

2007 Wildfire Litigation and Net Cost Recovery Status

SDG&E has resolved all litigation associated with three wildfires that occurred in October 2007.

As a result of a CPUC decision denying SDG&E’s request to recover wildfire costs, SDG&E wrote off the wildfire regulatory asset, resulting in a charge of $ 351 million ( $ 208 million after-tax) in the third quarter of 2017. SDG&E will continue to vigorously pursue recovery of these costs, which were incurred through settling claims brought under the doctrine of inverse condemnation. SDG&E applied to the CPUC for rehearing of its decision on January 2, 2018. On July 12, 2018, the CPUC adopted a decision denying the rehearing requests filed by SDG&E and other parties. On August 3, 2018, SDG&E filed an appeal with the California Court of Appeal seeking to reverse the CPUC’s decision. The filing also asked the court to direct the CPUC to award SDG&E recovery for payments made to settle inverse condemnation and limit any reasonableness review to the amounts of those payments. On September 7, 2018, the CPUC and two other parties filed responses with the California Court of Appeal requesting that SDG&E’s petition be denied. SDG&E submitted a reply to those parties on October 2, 2018 and is now awaiting court action on the appeal. The California Court of Appeal is not required to hear this appeal, in which case, SDG&E’s recourse would be to appeal this decision to the California Supreme Court.

SoCalGas

Aliso Canyon Natural Gas Storage Facility Gas Leak

On October 23, 2015, SoCalGas discovered a leak at one of its injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility (the Leak), located in the northern part of the San Fernando Valley in Los Angeles County. The Aliso Canyon natural gas storage facility has been operated by SoCalGas since 1972. SS25 is one of more than 100 injection-and-withdrawal wells at the storage facility. SoCalGas worked closely with several of the world’s leading experts to stop the Leak, and on February 18, 2016, DOGGR confirmed that the well was permanently sealed. SoCalGas calculated that approximately 4.62 Bcf of natural gas was released from the Aliso Canyon natural gas storage facility as a result of the Leak.

Local Community Mitigation Efforts. Pursuant to a stipulation and order by the LA Superior Court, SoCalGas provided temporary relocation support to residents in the nearby community who requested it before the well was permanently sealed. Following the permanent sealing of the well, the DPH conducted testing in certain homes in the Porter Ranch community, and concluded that indoor conditions did not present a long-term health risk and that it was safe for residents to return home. In May

2016, the LA Superior Court ordered SoCalGas to offer to clean residents’ homes at SoCalGas’ expense as a condition to ending the relocation program. SoCalGas completed the residential cleaning program and the relocation program ended in July 2016.

In May 2016, the DPH also issued a directive that SoCalGas additionally professionally clean (in accordance with the proposed protocol prepared by the DPH) the homes of all residents located within the Porter Ranch Neighborhood Council boundary, or who participated in the relocation program, or who are located within a five-mile radius of the Aliso Canyon natural gas storage facility and experienced symptoms from the Leak (the Directive). SoCalGas disputes the Directive, contending that it is invalid and unenforceable, and has filed a petition for writ of mandate to set aside the Directive.

The costs incurred to remediate and stop the Leak and to mitigate local community impacts have been significant and may increase, and we may be subject to potentially significant damages, restitution, and civil, administrative and criminal fines, penalties and other costs. To the extent any of these costs are not covered by insurance (including any costs in excess of applicable policy limits), if there were to be significant delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes, such amounts could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Cost Estimates and Accounting Impact. At September 30, 2018 , SoCalGas’ best estimate of costs related to the Leak was $ 1,039 million (the cost estimate), which includes $ 1,012 million of costs recovered or probable of recovery from insurance. Approximately 55 percent of the cost estimate is for the temporary relocation program (including cleaning costs and certain labor costs). The remaining portion of the cost estimate includes legal costs incurred to defend litigation, the estimated costs to settle certain actions, the estimated cost of the root cause analysis being conducted by an independent third party, efforts to control the well, the costs to mitigate the actual natural gas released, the value of lost gas, and other costs. The value of lost gas reflects the replacement cost of all lost gas. SoCalGas adjusts its estimated total liability associated with the Leak as additional information becomes available. A substantial portion of the cost estimate has been paid and $ 161 million is accrued as Reserve for Aliso Canyon Costs as of September 30, 2018 on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets for amounts expected to be paid after September 30, 2018 .

As of September 30, 2018 , we recorded the expected recovery of the cost estimate related to the Leak of $ 474 million as Insurance Receivable for Aliso Canyon Costs on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets. This amount is net of insurance retentions and $ 538 million of insurance proceeds we received through September 30, 2018 related to portions of the cost estimate described above, including temporary relocation costs, control-of-well expenses, legal costs and lost gas. If we were to conclude that this receivable or a portion of it is no longer probable of recovery from insurers, some or all of this receivable would be charged against earnings, which could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

As described in “Governmental Investigations and Civil and Criminal Litigation” below, the actions seek compensatory, statutory and punitive damages, restitution, and civil, administrative and criminal fines, penalties and other costs, which except for the amounts paid or estimated to settle certain actions, are not included in the cost estimate as it is not possible at this time to predict the outcome of these actions or reasonably estimate the amount of damages, restitution or civil, administrative or criminal fines, penalties or other costs that may be imposed. The recorded amounts above also do not include the costs to clean additional homes pursuant to the Directive, future legal costs necessary to defend litigation, and other potential costs that we currently do not anticipate incurring or that we cannot reasonably estimate. Furthermore, the cost estimate does not include certain other costs expensed by Sempra Energy through September 30, 2018 associated with defending against shareholder derivative lawsuits.

In March 2016, the CPUC ordered SoCalGas to establish a memorandum account to prospectively track its authorized revenue requirement and all revenues that it receives for its normal, business-as-usual costs to own and operate the Aliso Canyon natural gas storage facility and, in September 2016, approved SoCalGas’ request to begin tracking these revenues as of March 17, 2016. The CPUC will determine at a later time whether, and to what extent, the authorized revenues tracked in the memorandum account will be refunded to ratepayers.

Insurance. Excluding directors’ and officers’ liability insurance, we have at least four kinds of insurance policies that together we estimate provide between $ 1.2 billion to $ 1.4 billion in insurance coverage, depending on the nature of the claims. We cannot predict all of the potential categories of costs or the total amount of costs that we may incur as a result of the Leak. Subject to various policy limits, exclusions and conditions, based on what we know as of the filing date of this report, we believe that our insurance policies collectively should cover the following categories of costs: costs incurred for temporary relocation (including cleaning costs and certain labor costs), costs to address the Leak and stop or reduce emissions, the root cause analysis being conducted to investigate the cause of the Leak, the value of lost gas, costs incurred to mitigate the actual natural gas released, costs associated with litigation and claims by nearby residents and businesses, any costs to clean additional homes pursuant to the Directive, and, in some circumstances depending on their nature and manner of assessment, fines and penalties. We have been communicating with our insurance carriers and, as discussed above, we have received insurance payments for portions of the

costs described above, including temporary relocation costs, control-of-well expenses, legal costs and lost gas. We intend to pursue the full extent of our insurance coverage for the costs we have incurred or may incur. There can be no assurance that we will be successful in obtaining additional insurance recovery for these costs under the applicable policies, and to the extent we are not successful in obtaining coverage or these costs exceed the amount of our coverage, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

At September 30, 2018 , SoCalGas’ estimated costs related to the Leak of $ 1,039 million include $ 1,012 million of costs recovered or probable of recovery from insurance. This estimate may rise significantly as more information becomes available. Any costs not included in the $ 1,039 million cost estimate could be material. To the extent not covered by insurance (including any costs in excess of applicable policy limits), if there were to be significant delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes, such amounts could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Governmental Investigations and Civil and Criminal Litigation. Various governmental agencies, including DOGGR, DPH, SCAQMD, CARB, Los Angeles Regional Water Quality Control Board, California Division of Occupational Safety and Health, CPUC, PHMSA, EPA, Los Angeles County District Attorney’s Office and California Attorney General’s Office, have investigated or are investigating this incident. Other federal agencies (e.g., the DOE and the U.S. Department of the Interior) investigated the incident as part of a joint interagency task force. In January 2016, DOGGR and the CPUC selected Blade Energy Partners to conduct, under their supervision, an independent analysis of the technical root cause of the Leak, to be funded by SoCalGas. The timing of the root cause analysis is under the control of Blade Energy Partners, DOGGR and the CPUC.

As of November 2, 2018, 388 lawsuits, including approximately 48,000 plaintiffs, are pending against SoCalGas, some of which have also named Sempra Energy. All of these cases, other than a matter brought by the Los Angeles County District Attorney and the federal securities class action discussed below, are coordinated before a single court in the LA Superior Court for pretrial management (the Coordination Proceeding).

Pursuant to the Coordination Proceeding, in March 2017, the individuals and business entities asserting tort and Proposition 65 claims filed a Second Amended Consolidated Master Case Complaint for Individual Actions, through which their separate lawsuits will be managed for pretrial purposes. The consolidated complaint asserts causes of action for negligence, negligence per se, private and public nuisance (continuing and permanent), trespass, inverse condemnation, strict liability, negligent and intentional infliction of emotional distress, fraudulent concealment, loss of consortium and violations of Proposition 65 against SoCalGas, with certain causes also naming Sempra Energy. The consolidated complaint seeks compensatory and punitive damages for personal injuries, lost wages and/or lost profits, property damage and diminution in property value, injunctive relief, costs of future medical monitoring, civil penalties (including penalties associated with Proposition 65 claims alleging violation of requirements for warning about certain chemical exposures), and attorneys’ fees.

In January 2017, pursuant to the Coordination Proceeding, two consolidated class action complaints were filed against SoCalGas and Sempra Energy, one on behalf of a putative class of persons and businesses who own or lease real property within a five -mile radius of the well (the Property Class Action), and a second on behalf of a putative class of all persons and entities conducting business within five miles of the facility (the Business Class Action). Both complaints assert claims for strict liability for ultra-hazardous activities, negligence and violation of California Unfair Competition Law. The Property Class Action also asserts claims for negligence per se, trespass, permanent and continuing public and private nuisance, and inverse condemnation. The Business Class Action also asserts a claim for negligent interference with prospective economic advantage. Both complaints seek compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees. In December 2017, the California Court of Appeal, Second Appellate District ruled that the purely economic damages alleged in the Business Class Action are not recoverable under the law. In February 2018, the California Supreme Court granted a petition filed by the plaintiffs to review that ruling. In September and October of 2017, property developers filed two complaints, one of which was amended in July 2018, against SoCalGas and Sempra Energy alleging causes of action for strict liability, negligence per se, negligence, continuing nuisance, permanent nuisance and violation of the California Unfair Competition Law, as well as claims for negligence against certain directors of SoCalGas. The complaints seek compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees. These claims are joined in the Coordination Proceeding.

In October 2018, a complaint was filed on behalf of 36 plaintiffs who are firefighters stationed near the Aliso Canyon natural gas storage facility and allege they were injured by exposure to chemicals released during the Leak. The complaint against SoCalGas and Sempra Energy asserts causes of actions for negligence, negligence per se, private and public nuisance (continuing and permanent), trespass, inverse condemnation, strict liability, negligent and intentional infliction of emotional distress, fraudulent concealment and loss of consortium. The complaint seeks compensatory and punitive damages for personal injuries, lost wages and/or lost profits, property damage and diminution in property value, and attorney’s fees. SoCalGas expects this case will be joined in the Coordination Proceeding.

In addition to the lawsuits described above, a federal securities class action alleging violation of the federal securities laws has been filed against Sempra Energy and certain of its officers and certain of its directors in the United States District Court for the Southern District of California. In March 2018, the District Court dismissed the action with prejudice, and in April 2018 the plaintiffs moved for reconsideration of the order.

Five shareholder derivative actions are also pending in the Coordination Proceeding alleging breach of fiduciary duties against certain officers and certain directors of Sempra Energy and/or SoCalGas, four of which were joined in a Consolidated Shareholder Derivative Complaint in August 2017.

Three actions filed by public entities are pending in the Coordination Proceeding. First, in July 2016, the County of Los Angeles, on behalf of itself and the people of the State of California, filed a complaint against SoCalGas in the LA Superior Court for public nuisance, unfair competition, breach of franchise agreement, breach of lease, and damages. This suit alleges that the four natural gas storage fields operated by SoCalGas in Los Angeles County require safety upgrades, including the installation of a sub-surface safety shut-off valve on every well. It additionally alleges that SoCalGas failed to comply with the DPH Directive. It seeks preliminary and permanent injunctive relief, civil penalties, and damages for the County’s costs to respond to the Leak, as well as punitive damages and attorneys’ fees.

Second, in August 2016, the California Attorney General, acting in an independent capacity and on behalf of the people of the State of California and the CARB, together with the Los Angeles City Attorney, filed a third amended complaint on behalf of the people of the State of California against SoCalGas alleging public nuisance, violation of the California Unfair Competition Law, violations of California Health and Safety Code sections 41700 (prohibiting discharge of air contaminants that cause annoyance to the public) and 25510 (requiring reporting of the release of hazardous material), as well as California Government Code section 12607 for equitable relief for the protection of natural resources. The complaint seeks an order for injunctive relief, to abate the public nuisance, and to impose civil penalties.

Third, a petition for writ of mandate filed by the County of Los Angeles is pending against DOGGR and its State Oil and Gas Supervisor and the CPUC and its Executive Director, as to which SoCalGas is the real party in interest. The petition alleges that in issuing its July 2017 determination that the requirements for the resumption of injection operations were met (discussed under “Natural Gas Storage Operations and Reliability” below), DOGGR failed to comply with the provisions of SB 380, which requires a comprehensive safety review of the Aliso Canyon natural gas storage facility before injection of natural gas may resume. The County alleges, among other things, that DOGGR failed to comply with the provisions of SB 380 in declaring the safety review complete and authorizing the resumption of injection of natural gas into the facility before the root cause analysis was complete, failing to make its safety-review documents available to the public and failing to address seismic risks to the field as part of its safety review. The County further alleges that CEQA required DOGGR to prepare an EIR before the resumption of injection of natural gas at the facility may be approved. The petition seeks a writ of mandate requiring DOGGR and the State Oil and Gas Supervisor to comply with SB 380 and CEQA, and to produce records in response to the County’s Public Records Act request, as well as declaratory and injunctive relief against any authorization to inject natural gas and attorneys’ fees.

In August 2018, SoCalGas entered into a settlement agreement with the Los Angeles City Attorney’s Office, the County of Los Angeles, the California Office of the Attorney General and CARB (collectively, the Government Plaintiffs) to settle the three public entity actions for payments and funding for environmental projects totaling $ 120 million , including $ 21 million in civil penalties (the Government Plaintiffs Settlement). Under the settlement agreement, SoCalGas agreed to continue its fence line methane monitoring program, establish a safety committee and hire an independent ombudsman to monitor and report on the safety at the facility. This settlement also fully resolves SoCalGas’ commitment to mitigate the actual natural gas released during the Leak and fulfills the requirements of the Governor’s Order, described below, for SoCalGas to pay for a mitigation program developed by CARB. The Government Plaintiffs Settlement requires the approval of the LA Superior Court.

Separately, in February 2016, the Los Angeles County District Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties and other remedies for alleged failure to provide timely notice of the Leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a), and for allegedly violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public. Pursuant to a settlement agreement with the Los Angeles County District Attorney’s Office, SoCalGas agreed to plead no contest to the notice charge under Health and Safety Code section 25510(a) and agreed to pay the maximum fine of $ 75,000 , penalty assessments of approximately $ 233,500 , and operational commitments estimated to cost approximately $ 6 million , reimbursement and assessments in exchange for the Los Angeles County District Attorney’s Office moving to dismiss the remaining counts at sentencing and settling the complaint (the District Attorney Settlement). In November 2016, SoCalGas completed the commitments and obligations under the District Attorney Settlement, and on November 29, 2016, the LA Superior Court approved the settlement and entered judgment on the notice charge. Certain individuals who object to the settlement have filed an appeal of the judgment, contending they should be granted restitution.

The costs of defending against these civil and criminal lawsuits, cooperating with these investigations, and any damages, restitution, and civil, administrative and criminal fines, penalties and other costs, if awarded or imposed, as well as the costs of mitigating the actual natural gas released, could be significant and to the extent not covered by insurance (including any costs in excess of applicable policy limits), if there were to be significant delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes, such amounts could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Regulatory Proceedings. In February 2017, the CPUC opened a proceeding pursuant to SB 380 to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region. The CPUC indicated it intends to conduct the proceeding in two phases, with Phase 1 undertaking a comprehensive effort to develop the appropriate analyses and scenarios to evaluate the impact of reducing or eliminating the use of the Aliso Canyon natural gas storage facility and Phase 2 using those analyses and scenarios to evaluate the impacts of reducing or eliminating the use of the Aliso Canyon natural gas storage facility.

The order establishing the scope of the proceeding expressly excludes issues with respect to air quality, public health, causation, culpability or cost responsibility regarding the Leak. The CPUC adopted an initial Phase 1 schedule contemplating public participation hearings and workshops beginning in April 2017, but no hearings until Phase 2. In May 2018, the CPUC updated the Phase 1 schedule, providing for Phase 1 to be concluded November 14, 2018 with issuance of a Ruling Adopting Scenarios, Assumptions and Models.

Section 455.5 of the California Public Utilities Code, among other things, directs regulated utilities to notify the CPUC if all or any portion of a major facility has been out of service for nine consecutive months. Although SoCalGas did not believe the Aliso Canyon natural gas storage facility or any portion of the facility was out of service (as that term is meant in section 455.5) for nine consecutive months, SoCalGas provided notification out of an abundance of caution to demonstrate its commitment to regulatory compliance and transparency, and because obtaining authorization to resume injection operations at the facility required more time than initially contemplated. In response, and as required by section 455.5, the CPUC issued an OII to address whether the Aliso Canyon natural gas storage facility or any portion of the facility was out of service for nine consecutive months under section 455.5, and if so, whether the CPUC should disallow costs for such period from SoCalGas’ rates. In September 2018, the CPUC issued a final decision finding that the Aliso Canyon natural gas storage facility was not out of service for nine consecutive months.

Governmental Orders and Additional Regulation. In January 2016, the Governor of the State of California issued an order (the Governor’s Order) proclaiming a state of emergency in Los Angeles County due to the Leak. The Governor’s Order imposes various orders with respect to: stopping the Leak; protecting public health and safety; ensuring accountability; and strengthening oversight. Most of the directives in the Governor’s Order have been fulfilled, with the following remaining open items: (1) applicable agencies must convene an independent panel of scientific and medical experts to review public health concerns stemming from the natural gas leak and evaluate whether additional measures are needed to protect public health; (2) the CPUC must ensure that SoCalGas covers costs related to the natural gas leak and its response while protecting ratepayers; (3) CARB must develop a program to fully mitigate the leak’s emissions of methane by March 31, 2016, with such program to be funded by SoCalGas; and (4) DOGGR, CPUC, CARB and the CEC must submit to the Governor’s Office a report that assesses the long-term viability of natural gas storage facilities in California. The development of a mitigation program per the Government Plaintiffs Settlement, discussed above, satisfies the third remaining open item.

In December 2015, SoCalGas made a commitment to mitigate the actual natural gas released from the Leak and has been working on a plan to accomplish the mitigation. In March 2016, pursuant to the Governor’s Order, the CARB issued its Aliso Canyon Methane Leak Climate Impacts Mitigation Program , which set forth its recommended approach to achieve full mitigation of the emissions from the Leak. In October 2016, CARB issued its final report concluding that the incident resulted in total emissions from 90,350 to 108,950 metric tons of methane, and asserting that SoCalGas should mitigate 109,000 metric tons of methane to fully mitigate the GHG impacts of the Leak. The Government Plaintiffs Settlement described above fully resolves SoCalGas’ commitment to mitigate the actual natural gas released from the Leak.

Natural Gas Storage Operations and Reliability. Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and heating needs in the winter. The Aliso Canyon natural gas storage facility, with a storage capacity of 86 Bcf (which represents 63 percent of SoCalGas’ natural gas storage inventory capacity), is the largest SoCalGas storage facility and an important element of SoCalGas’ delivery system. Beginning October 25, 2015, pursuant to orders by DOGGR and the Governor of the State of California, and in accordance with SB 380, SoCalGas suspended injection of natural gas into the Aliso Canyon natural gas storage facility. In April and June of 2017, SoCalGas advised the California ISO, CEC, CPUC and PHMSA of its concerns that the inability to inject natural gas into the Aliso Canyon natural gas storage facility posed a risk to energy reliability in Southern California. Limited withdrawals of natural

gas from the Aliso Canyon natural gas storage facility have been made to augment natural gas supplies during critical demand periods.

On July 19, 2017, DOGGR issued its determination that SoCalGas had met the requirements of SB 380 for the resumption of injection operations, including all safety requirements. On the same date, the CPUC’s Executive Director issued his concurrence with that determination, and DOGGR issued its Order to: Test and Take Temporary Actions Upon Resuming Injection: Aliso Canyon Gas Storage Facility lifting the prohibition on injection at the Aliso Canyon natural gas storage facility, subject to certain requirements after injection resumed, including limitations on the rate at which SoCalGas may withdraw natural gas from the field. The County of Los Angeles filed a petition for writ of mandate seeking declaratory and injunctive relief and a stay of DOGGR’s order lifting the prohibition against injecting natural gas at the facility. We provide further detail regarding the County of Los Angeles’ suit and the settlement agreement to resolve this dispute, which is subject to the approval of the LA Superior Court, above in “Governmental Investigations and Civil and Criminal Litigation.” Having completed the steps outlined by state agencies to safely begin injections at the Aliso Canyon natural gas storage facility, as of July 31, 2017, SoCalGas resumed limited injections. The CPUC has issued a series of directives to SoCalGas establishing the range of working gas to be maintained in the Aliso Canyon natural gas storage facility to help ensure safety and reliability for the region and just and reasonable rates in California, the most recent of which, issued July 2, 2018, directed SoCalGas to maintain up to 34 Bcf of working gas.

If the Aliso Canyon natural gas storage facility were to be permanently closed, or if future cash flows were otherwise insufficient to recover its carrying value, it could result in an impairment of the facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At September 30, 2018 , the Aliso Canyon natural gas storage facility had a net book value of $ 696 million , including $ 285 million for the recently completed construction of a new compressor station. Any significant impairment of this asset could have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations for the period in which it is recorded. Higher operating costs and additional capital expenditures incurred by SoCalGas may not be recoverable in customer rates, and could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Sempra Mexico

Property Disputes and Permit Challenges

Energía Costa Azul. Sempra Mexico has been engaged in a long-running land dispute relating to property adjacent to its ECA LNG terminal near Ensenada, Mexico. A claimant to the adjacent property filed complaints in the federal Agrarian Court challenging the refusal of SEDATU in 2006 to issue a title to him for the disputed property. In November 2013, the federal Agrarian Court ordered that SEDATU issue the requested title and cause it to be registered. Both SEDATU and Sempra Mexico challenged the ruling, due to lack of notification of the underlying process. Both challenges are pending to be resolved by a Federal Court in Mexico. Sempra Mexico expects additional proceedings regarding the claims.

Several administrative challenges are pending in Mexico before the Mexican environmental protection agency and the Federal Tax and Administrative Courts seeking revocation of the environmental impact authorization issued to ECA in 2003. These cases generally allege that the conditions and mitigation measures in the environmental impact authorization are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines.

Additionally, in August 2018, a claimant filed a challenge in the federal district court in Ensenada, Baja California in relation to the environmental and social impact permits issued to ECA in September 2017 and December 2017, respectively, to allow natural gas liquefaction activities at the ECA LNG terminal. The court issued a provisional injunction on September 28, 2018 that has uncertain application and requires clarification by the court, which is being pursued through additional proceedings.

Cases involving t wo parcels of real property have been filed against ECA. In one case, filed in the federal Agrarian Court in 2006, the plaintiffs seek to annul the recorded property title for a parcel on which the ECA LNG terminal is situated and to obtain possession of a different parcel that allegedly sits in the same place. Another civil complaint filed in the state court was served in April 2012 seeking to invalidate the contract by which ECA purchased another of the terminal parcels, on the grounds the purchase price was unfair; the plaintiff filed a second complaint in 2013 in the federal Agrarian Court seeking an order that SEDATU issue title to her. In January 2016, the federal Agrarian Court ruled against the plaintiff, and the plaintiff appealed the ruling. In May 2018, the state court dismissed the civil complaint, and the plaintiff has appealed. Sempra Mexico expects further proceedings on these two matters.

Guaymas-El Oro Segment of the Sonora Pipeline. IEnova’s Sonora natural gas pipeline consists of two segments, the Sasabe-Puerto Libertad-Guaymas segment, and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. In 2015, the Yaqui tribe, with the exception of some members living in the Bácum community, granted its consent and a right-of-way easement agreement for the construction of the Guaymas-El Oro segment of the Sonora natural gas pipeline that crosses its

territory. Representatives of the Bácum community filed a legal challenge in Mexican Federal Court demanding the right to withhold consent for the project, the stoppage of work in the Yaqui territory and damages. In 2016, the judge granted a suspension order that prohibited the construction of such segment through the Bácum community territory. Because the pipeline does not pass through the Bácum community, IEnova did not believe the 2016 suspension order prohibited construction in the remainder of the Yaqui territory. Because of the dispute, however, IEnova was delayed in the construction of the approximately 14 kilometers of pipeline that pass through territory of the Yaqui tribe. IEnova declared a force majeure under its contract with the CFE as a result of such construction delays. The CFE agreed to extend the deadline for commercial operations of the Guaymas-El Oro segment until the second quarter of 2017 and to pay fixed charge payments pursuant to the service agreement during such extension. Construction of the Guaymas-El Oro segment was completed, and commercial operations began in May 2017.

Following the start of commercial operations of the Guaymas-El Oro segment, an appellate court ruled that the scope of the 2016 suspension order encompassed the wider Yaqui territory. The legal challenge remains pending. IEnova has subsequently reported damage and declared a force majeure event for the Guaymas-El Oro segment of the Sonora pipeline in the Yaqui territory that has interrupted its operations since August 23, 2017. IEnova will continue to exercise its rights under the contract, which include (i) force majeure payments; and (ii) just compensation following the expiration of the period such force majeure payments are required to be made. The Sasabe-Puerto Libertad-Guaymas segment of the Sonora pipeline remains in full operation.

Other Litigation

Sempra Energy holds a noncontrolling interest in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. NatWest Markets Plc, formerly RBS, our partner in the joint venture, paid an assessment of £ 86 million (approximately $ 138 million in U.S. dollars) in October 2014 to HMRC for denied VAT refund claims filed in connection with the purchase of carbon credit allowances by RBS SEE, a subsidiary of RBS Sempra Commodities. RBS SEE has since been sold to JP Morgan and later to Mercuria Energy Group, Ltd. HMRC asserted that RBS was not entitled to reduce its VAT liability by VAT paid on certain carbon credit purchases during 2009 because RBS knew or should have known that certain vendors in the trading chain did not remit their own VAT to HMRC. After paying the assessment, RBS filed a Notice of Appeal of the assessment with the First-Tier Tribunal. The First-Tier Tribunal held a preliminary hearing in September 2016 to determine whether HMRC’s assessment was time-barred. In January 2017, the First-Tier Tribunal ruled that HMRC’s assessment was timely. There will be a hearing on the substantive matter regarding whether RBS knew or should have known that certain vendors in the trading chain did not remit their VAT to HMRC.

During 2015, liquidators acting on behalf of ten companies (the Liquidating Companies) that engaged in carbon credit trading via chains that included a company that RBS SEE traded with directly filed a claim in the High Court of Justice asserting damages of £ 160 million (approximately $ 209 million in U.S. dollars at September 30, 2018 ) against RBS and Mercuria Energy Europe Trading Limited (the Defendants). The claim alleges that the Defendants’ participation in the purchase and sale of carbon credits resulted in the Liquidating Companies’ carbon credit trading transactions creating a VAT liability they were unable to pay. The £ 160 million is comprised of a claim by the Liquidating Companies for £ 80 million (approximately $ 104 million in U.S. dollars at September 30, 2018 ) for equitable compensation due to dishonest assistance, and a claim by the liquidators for compensation in the same amount under the U.K. Insolvency Act of 1986. The parties have agreed that to the extent the Liquidating Companies’ claims are successful, the liquidators cannot collect under the U.K. Insolvency Act of 1986; however, the award amount is ultimately determined by the court. The hearing for this matter began on June 14, 2018 and concluded on July 20, 2018. On the final day of the trial, the claimants withdrew a portion of their claim, which reduced the £ 160 million claim to £ 143 million (approximately $ 186 million in U.S. dollars at September 30, 2018 ), equally split between the Liquidating Companies and the liquidators. JP Morgan has notified us that Mercuria Energy Group, Ltd. has sought indemnity for the claim, and JP Morgan has in turn sought indemnity from Sempra Energy and RBS.

While the ultimate outcome remains uncertain, we continue to evaluate the likelihood of recovery of our investment. Accordingly, in the third quarter of 2018, we fully impaired our remaining $ 65 million equity method investment in RBS Sempra Commodities, which is included in Equity Earnings on Sempra Energy’s Condensed Consolidated Statement of Operations.

Certain EFH subsidiaries that we acquired as part of the Merger are defendants in personal injury lawsuits brought in state courts throughout the U.S. As of November 2, 2018, 115 such lawsuits are pending. These cases allege illness or death as a result of exposure to asbestos in power plants designed and/or built by companies whose assets were purchased by predecessor entities to the EFH subsidiaries, and generally assert claims for product defects, negligence, strict liability and wrongful death. They seek compensatory and punitive damages. Additionally, in connection with the EFH bankruptcy proceeding, approximately 28,000 proofs of claim were filed on behalf of persons who allege exposure to asbestos under similar circumstances and assert the right to file such lawsuits in the future. We anticipate additional lawsuits will be filed. None of these claims or lawsuits were discharged in the EFH bankruptcy proceeding.

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We are also defendants in ordinary routine litigation incidental to our businesses, including personal injury, employment litigation, product liability, property damage and other claims. Juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.

CONTRACTUAL COMMITMENTS

We discuss below significant changes in the first nine months of 2018 to contractual commitments discussed in Notes 1 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Natural Gas Contracts

SoCalGas’ reservation charges for interstate pipeline capacity agreements have increased by $ 158 million since December 31, 2017 primarily due to new capacity agreements entered into in the third quarter of 2018, which replace existing or expiring agreements. Net future payments are expected to decrease by $ 79 million in 2018, and increase by $ 57 million in 2019, $ 89 million in 2020, $ 79 million in 2021 and $ 12 million in 2022 compared to December 31, 2017 .

Sempra LNG & Midstream’s natural gas purchase and transportation commitments have decreased by $ 61 million since December 31, 2017 , primarily due to payments on existing contracts and changes in forward natural gas prices in the first nine months of 2018 . We expect net future payments to decrease by $ 147 million in 2018, and increase by $ 33 million in 2019, $ 10 million in 2020, $ 6 million in 2021, $ 4 million in 2022 and $ 33 million thereafter compared to December 31, 2017 .

LNG Purchase Agreement

Sempra LNG & Midstream has a sale and purchase agreement for the supply of LNG to the ECA terminal. The commitment amount is calculated using a predetermined formula based on estimated forward prices of the index applicable from 2018 to 2029. At September 30, 2018 , we expect the commitment amount to decrease by $ 288 million in 2018, increase by $ 23 million in 2019, and decrease by $ 22 million in 2020, $ 41 million in 2021, $ 56 million in 2022 and $ 230 million thereafter (through contract termination in 2029) compared to December 31, 2017 , reflecting changes in estimated forward prices since December 31, 2017 and actual transactions for the first nine months of 2018. These LNG commitment amounts are based on the assumption that all LNG cargoes, less those already confirmed to be diverted, under the agreement are delivered. Although this agreement specifies a number of cargoes to be delivered, under its terms, the customer may divert certain cargoes, which would reduce amounts paid under the agreement by Sempra LNG & Midstream. Actual LNG purchases in the current and prior years have been significantly lower than the maximum amount provided under the agreement due to the customer electing to divert cargoes as allowed by the agreement.

Construction and Development Projects

Sempra Mexico

In the first nine months of 2018, significant net increases to contractual commitments at Sempra Mexico were $ 90 million , primarily for contracts related to the construction of liquid fuels terminals and the construction of renewables projects. We expect net future payments under these contractual commitments to increase by $ 54 million in 2018, $ 34 million in 2019 and $ 2 million thereafter compared to December 31, 2017.

Sempra Mexico was awarded a 20-year concession with the Administración Portuaria Integral de Topolobampo, S.A. de C.V. for the right to build, use, leverage and benefit from the operation of the marine terminal in the Port of Topolobampo in Sinaloa. The agreement will commence in the fourth quarter of 2018 and terminate in 2038 (subject to a renewal option). We expect future payments under this contractual commitment to be $ 110 million in total, with payments of $ 19 million in 2018, $ 2 million in each of 2019 and 2020, $ 3 million in each of 2021 and 2022, and $ 81 million thereafter.

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CONCENTRATION OF CREDIT RISK

We maintain credit policies and systems designed to manage our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. We grant credit to utility customers and counterparties, substantially all of whom are located in our service territory, which covers most of Southern California and a portion of central California for SoCalGas, and all of San Diego County and an adjacent portion of Orange County for SDG&E. We also grant credit to utility customers and counterparties of our other companies providing natural gas or electric services in Mexico, Chile and Peru.

Projects and businesses owned or partially owned by Sempra Energy place significant reliance on the ability of their suppliers, customers and partners to perform on long-term agreements and on our ability to enforce contract terms in the event of nonperformance. We consider many factors, including the negotiation of supplier and customer agreements, when we evaluate and approve development projects and investment opportunities.

NOTE 12. SEGMENT INFORMATION

We have seven separately managed, reportable segments, as follows:

▪ 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 Texas Utility holds our investment in Oncor Holdings, which owns an 80.25 -percent interest in Oncor, a regulated electric transmission and distribution utility serving customers in the north-central, eastern and western parts of Texas. As we discuss in Note 5, we completed our acquisition of the investment in March 2018.

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

▪ Sempra Mexico develops, owns and operates, or holds interests in, natural gas, electric, LNG, LPG, ethane and liquid fuels infrastructure, and has marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico.

▪ Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy generation facilities serving wholesale electricity markets in the U.S. In June 2018, our board of directors approved a plan to market and sell all the segment’s wind assets and investments and solar assets and investments, as we discuss in Note 5.

▪ Sempra LNG & Midstream develops, owns and operates, or holds interests in, a terminal for the import and export of LNG and sale of natural gas, and natural gas pipelines, storage facilities and marketing operations, all within the U.S. In June 2018, our board of directors approved a plan to market and sell our natural gas storage assets at Mississippi Hub and our 90.9 -percent ownership interest in Bay Gas, as we discuss in Note 5.

We evaluate each segment’s performance based on its contribution to Sempra Energy’s reported earnings and cash flows. The California Utilities operate in essentially separate service territories, under separate regulatory frameworks and rate structures set by the CPUC. The California Utilities’ operations are based on rates set by the CPUC and the FERC. We describe the accounting policies of all of our segments in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

The cost of common services shared by the business segments is assigned directly or allocated based on various cost factors, depending on the nature of the service provided. Interest income and expense is recorded on intercompany loans. The loan balances and related interest are eliminated in consolidation.

The following tables show selected information by segment from our Condensed Consolidated Statements of Operations and Condensed Consolidated Balance Sheets. Amounts labeled as “All other” in the following tables consist primarily of activities of parent organizations.

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SEGMENT INFORMATION
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
REVENUES
SDG&E	$ 1,299		$ 1,236		$ 3,405		$ 3,351
SoCalGas	802		684		2,700		2,695
Sempra South American Utilities	375		376		1,190		1,169
Sempra Mexico	410		336		1,028		873
Sempra Renewables	38		26		103		74
Sempra LNG & Midstream	147		152		330		406
Adjustments and eliminations	—		—		( 2	)	—
Intersegment revenues (1)	( 131	)	( 131	)	( 288	)	( 325	)
Total	$ 2,940		$ 2,679		$ 8,466		$ 8,243
INTEREST EXPENSE
SDG&E	$ 56		$ 53		$ 161		$ 151
SoCalGas	29		26		82		77
Sempra South American Utilities	10		10		30		30
Sempra Mexico	30		21		90		73
Sempra Renewables	5		3		15		11
Sempra LNG & Midstream	3		9		18		29
All other	122		74		371		209
Intercompany eliminations	( 23	)	( 31	)	( 82	)	( 87	)
Total	$ 232		$ 165		$ 685		$ 493
INTEREST INCOME
SDG&E	$ 1		$ —		$ 3		$ —
SoCalGas	—		1		1		1
Sempra South American Utilities	6		6		19		17
Sempra Mexico	17		7		48		12
Sempra Renewables	2		1		6		4
Sempra LNG & Midstream	10		14		36		43
All other	1		1		14		1
Intercompany eliminations	( 15	)	( 18	)	( 51	)	( 52	)
Total	$ 22		$ 12		$ 76		$ 26
DEPRECIATION AND AMORTIZATION
SDG&E	$ 174		$ 170		$ 509		$ 499
SoCalGas	141		132		414		384
Sempra South American Utilities	14		14		43		40
Sempra Mexico	45		41		131		114
Sempra Renewables	—		9		27		28
Sempra LNG & Midstream	2		10		24		31
All other	4		2		10		10
Total	$ 380		$ 378		$ 1,158		$ 1,106
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$ 53		$ ( 72	)	$ 151		$ 72
SoCalGas	( 7	)	( 14	)	75		103
Sempra South American Utilities	23		18		64		57
Sempra Mexico	126		34		226		278
Sempra Renewables	( 2	)	( 9	)	( 67	)	( 25	)
Sempra LNG & Midstream	6		( 2	)	( 488	)	17
All other	( 32	)	( 39	)	( 88	)	( 124	)
Total	$ 167		$ ( 84	)	$ ( 127	)	$ 378

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SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
EQUITY EARNINGS (LOSSES)
Equity earnings (losses) before income tax:
Sempra Renewables	$ 12		$ 7		$ ( 170	)	$ 25
Sempra LNG & Midstream	—		3		1		6
All other	( 64	)	—		( 67	)	—
	( 52	)	10		( 236	)	31
Equity earnings (losses) net of income tax:
Sempra Texas Utility	154		—		283		—
Sempra South American Utilities	—		1		1		2
Sempra Mexico	( 28	)	2		2		( 7	)
	126		3		286		( 5	)
Total	$ 74		$ 13		$ 50		$ 26
EARNINGS (LOSSES) ATTRIBUTABLE TO COMMON SHARES
SDG&E	$ 205		$ ( 28	)	$ 521		$ 276
SoCalGas (2)	( 14	)	7		244		268
Sempra Texas Utility	154		—		283		—
Sempra South American Utilities	50		42		140		134
Sempra Mexico	44		66		161		105
Sempra Renewables	34		15		( 54	)	49
Sempra LNG & Midstream	16		( 4	)	( 764	)	24
All other (2)	( 215	)	( 41	)	( 471	)	( 99	)
Total	$ 274		$ 57		$ 60		$ 757
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E					$ 1,194		$ 1,122
SoCalGas					1,127		1,033
Sempra South American Utilities					161		138
Sempra Mexico					255		193
Sempra Renewables					46		361
Sempra LNG & Midstream					19		16
All other					13		17
Total					$ 2,815		$ 2,880
					September 30, 2018		December 31, 2017
ASSETS
SDG&E					$ 18,512		$ 17,844
SoCalGas					14,947		14,159
Sempra Texas Utility					9,553		—
Sempra South American Utilities					4,094		4,060
Sempra Mexico					9,103		8,554
Sempra Renewables					2,617		2,898
Sempra LNG & Midstream					3,722		4,872
All other					851		915
Intersegment receivables					( 2,794	)	( 2,848	)
Total					$ 60,605		$ 50,454
EQUITY METHOD AND OTHER INVESTMENTS
Sempra Texas Utility					$ 9,553		$ —
Sempra South American Utilities					17		16
Sempra Mexico					682		624
Sempra Renewables					600		813
Sempra LNG & Midstream					1,252		997
All other					10		77
Total					$ 12,114		$ 2,527

(1) Revenues for reportable segments include intersegment revenues of $ 1 million , $ 15 million , $ 31 million and $ 84 million for the three months ended September 30, 2018 ; $ 3 million , $ 47 million , $ 88 million and $ 150 million for the nine months ended September 30, 2018 ; $ 1 million , $ 21 million , $ 27 million and $ 82 million for the three months ended September 30, 2017 ; and $ 5 million , $ 56 million , $ 78 million and $ 186 million for the nine months ended September 30, 2017 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG & Midstream, respectively.

(2) After preferred dividends.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion in conjunction with the Condensed Consolidated Financial Statements and the Notes thereto and “Item 1A. Risk Factors” contained in this Form 10-Q, and the Consolidated Financial Statements and the Notes thereto, “Item 7. MD&A” and “Item 1A. Risk Factors” contained in the Annual Report.

OVERVIEW

Sempra Energy is a Fortune 500 energy-services holding company. Our businesses, which consist of seven separately managed reportable segments, invest in, develop and operate energy infrastructure, and provide electric and gas services to customers in North and South America.

We provide additional information about our reportable segments in Note 12 of the Notes to Condensed Consolidated Financial Statements herein and in “Item 1. Business” in the Annual Report.

Our Sempra Texas Utility reportable segment holds our equity method investment in Oncor Holdings, which we acquired in March 2018 and which owns an 80.25-percent interest in Oncor, a regulated electric transmission and distribution utility that we describe below in “New Reportable Segment.”

This report includes information for the following separate registrants:

▪ Sempra Energy and its consolidated entities

▪ SDG&E and its consolidated VIE

▪ SoCalGas

References to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by the context. We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include our Texas utility, South American utilities or the utility in our Sempra Mexico segment.

Throughout this report, we refer to the following as Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements when discussed together or collectively:

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

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

▪ the Condensed Financial Statements and related Notes of SoCalGas.

NEW REPORTABLE SEGMENT

Sempra Texas Utility

Sempra Texas Utility is comprised of our equity method investment in Oncor Holdings, which we acquired in March 2018. We discuss the acquisition in Note 5 of the Notes to Condensed Consolidated Financial Statements herein. Oncor Holdings is a direct, wholly owned subsidiary of Sempra Texas Intermediate Holding Company LLC, and owns an 80.25-percent interest in Oncor. TTI owns the remaining 19.75 percent interest in Oncor. Oncor is a limited liability company organized under the laws of the State of Delaware, formed in 2007 as the successor entity to Oncor Electric Delivery Company, a corporation formed under the laws of the State of Texas in 2001.

As we discuss in Notes 5 and 6 of the Notes to Condensed Consolidated Financial Statements herein and below in “MD&A – Factors Influencing Future Performance,” due to the structural and operational ring-fencing measures in place that prevent us from having the power to direct the significant activities of Oncor Holdings and Oncor, we account for our 100-percent ownership interest in Oncor Holdings as an equity method investment. Accordingly, Oncor’s operations are conducted, and its cash flows are managed, independently from Sempra Energy.

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Business Overview

Oncor is a regulated electric transmission and distribution utility that serves a population of approximately 10 million in the north-central, eastern and western parts of Texas, representing approximately 40 percent of the population of Texas. It provides the essential service of delivering electricity to end-use consumers through its electrical systems, as well as providing transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas.

At December 31, 2017, Oncor had approximately 3,965 full-time employees, including approximately 750 employees under collective bargaining agreements.

Customers and Demand. Oncor operates the largest transmission and distribution system in Texas, delivering electricity to more than 3.5 million homes and businesses and operating approximately 135,000 miles of transmission and distribution lines as of December 31, 2017. Oncor is not a seller of electricity, nor does it purchase electricity for resale. Rather, Oncor provides transmission services to electricity distribution companies, cooperatives and municipalities, and distribution services to retail electric providers that sell electricity to retail customers. At December 31, 2017, Oncor’s distribution customers consisted of approximately 85 retail electric providers and certain electric cooperatives in its certificated service area. The consumers of the electricity Oncor delivers are free to choose their electricity supplier from retail electric providers who compete for their business.

Oncor’s transmission and distribution assets are located principally in the north-central, eastern and western parts of Texas. Its territory is comprised of 99 counties and more than 400 incorporated municipalities, including Dallas/Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler and Killeen. Most of Oncor’s power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way as permitted by law.

Oncor’s revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.

Electricity Transmission. Oncor’s electricity transmission business is responsible for the safe and reliable operations of its transmission network and substations. These responsibilities consist of the construction and maintenance of transmission facilities and substations and the monitoring, controlling and dispatching of high-voltage electricity over its transmission facilities in coordination with ERCOT, which we discuss below in “Regulation.”

At December 31, 2017, Oncor’s transmission system included approximately 16,000 circuit miles of transmission lines, 301 transmission stations and 730 distribution substations, which are interconnected to 74 generation facilities totaling 36,819 MW.

Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to an interconnection to other markets, the FERC. Network transmission revenues compensate Oncor for delivery of electricity over transmission facilities operating at 60 kV and above. Other services offered by Oncor through its transmission business include system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.

Electricity Distribution. Oncor’s electricity distribution business is responsible for the overall operation of distribution facilities, including electricity delivery, power quality and system reliability. These responsibilities consist of the ownership, management, construction, maintenance and operation of the distribution system within its certificated service area. Oncor’s distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through 3,505 distribution feeders.

Oncor’s distribution system included over 3.5 million points of delivery at December 31, 2017 and consisted of approximately 119,000 miles of overhead conductors and underground conductors.

Distribution revenues from residential and small business users are based on actual monthly consumption (kilowatt hours), and, depending on size and annual load factor, revenues from large commercial and industrial users are based either on actual monthly demand (kilowatts) or the greater of actual monthly demand (kilowatts) or 80 percent of peak monthly demand during the prior eleven months.

Regulation

Texas State Utility Regulation. Oncor’s transmission and distribution rates are regulated by the PUCT and certain cities, and in certain instances, by the FERC. The PUCT has original jurisdiction over transmission and distribution rates and services in unincorporated areas and in those municipalities that have ceded original jurisdiction to the PUCT, and has exclusive appellate jurisdiction to review the rate and service orders and ordinances of municipalities. Generally, the Texas PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that do not have the prior approval of the appropriate regulatory authority (i.e., the PUCT or the municipality with original jurisdiction).

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At the state level, PURA requires owners or operators of transmission facilities to provide open-access wholesale transmission services to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility’s own use of its system. The PUCT has adopted rules implementing the state open-access requirements for all utilities that are subject to the PUCT’s jurisdiction over transmission services, including Oncor.

ERCOT Market. Oncor operates within the ERCOT market. This market represents approximately 90 percent of the electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the ISO of the interconnected transmission grid for those systems. ERCOT is responsible for ensuring reliability, adequacy and security of the electric systems, as well as nondiscriminatory access to transmission service by all wholesale market participants in the ERCOT region. ERCOT’s membership consists of corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, transmission service providers, distribution services providers, independent retail electric providers and consumers.

The ERCOT market operates under reliability standards set by the North American Electric Reliability Corporation. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of power supply across Texas’ main interconnected transmission grid. Oncor, along with other owners of transmission and distribution facilities in Texas, assists the ERCOT ISO in its operations. Oncor has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated distribution service area. Oncor participates with the ERCOT ISO and other ERCOT utilities in obtaining regulatory approvals and planning, designing, constructing and upgrading transmission lines in order to remove existing constraints and interconnect generation on the ERCOT transmission grid. The transmission line projects are necessary to meet reliability needs, support energy production and increase bulk power transfer capability.

Oncor is subject to reliability standards adopted and enforced by the Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with the North American Electric Reliability Corporation (including critical infrastructure protection) standards and ERCOT protocols.

Ratemaking Mechanisms

Rates and Cost Recovery. Oncor’s rates are regulated by the PUCT and certain cities, and are subject to regulatory rate-setting processes and annual earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Oncor’s rates are regulated based on an analysis of its costs and capital structure, as reviewed and approved in a regulatory proceeding. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. However, there is no assurance that the PUCT will judge all of Oncor’s costs to have been prudently incurred, that the PUCT will not reduce the amount of invested capital included in the capital structure that Oncor’s rates are based upon, that the regulatory process in which rates are determined will always result in rates that produce full recovery of Oncor’s costs or that Oncor’s authorized ROE will not be reduced.

The PURA allows utilities to file, under certain circumstances, once per year and up to four rate adjustments between comprehensive base rate proceedings to recover distribution-related investments on an interim basis. PUCT substantive rules also allow Oncor to update its transmission rates periodically to reflect changes in invested capital. These “capital tracker” provisions encourage investment in the electric system to help ensure reliability and efficiency by allowing for timely recovery of and return on new investments.

Capital Structure and Return on Equity. In October 2017, the PUCT approved the 2017 rate review (as supplemented by a settlement agreement), and Oncor’s new rates took effect on November 27, 2017. As a result of the PUCT order, Oncor is required to record as a regulatory liability, instead of revenue, the amount that Oncor collects through approved tariffs for federal income taxes that is above the new corporate federal income tax rate. Oncor’s current PUCT-authorized ROE is 9.8 percent and its authorized regulatory capital structure is 57.5 percent debt to 42.5 percent equity. Oncor’s previous authorized ROE was 10.25 percent with an authorized regulatory capital structure of 60 percent debt to 40 percent equity. The PUCT required Oncor to record a regulatory liability until the new authorized regulatory capital structure was met in order to reflect Oncor’s actual capitalization prior to achieving the authorized capital structure. Oncor implemented the regulatory liability as of November 27, 2017. Oncor attained the authorized capital structure in May 2018, and returned the regulatory liability of $6 million to customers in September 2018 through the capital structure refund mechanism approved in the PUCT order issued in the 2017 rate review.

Sempra Energy contributed $117 million in cash, commensurate with our ownership interest, to Oncor on April 23, 2018 in accordance with the terms of the Merger Agreement to enable Oncor to achieve its required capital structure calculated for regulatory purposes.

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RESULTS OF OPERATIONS

We discuss the following in Results of Operations:

▪ Overall results of our operations

▪ Segment results

▪ Adjusted earnings and adjusted earnings per common share

▪ Significant changes in revenues, costs and earnings between periods

▪ Impact of foreign currency and inflation rates on our results of operations

OVERALL RESULTS OF OPERATIONS OF SEMPRA ENERGY

Our earnings increased by $217 million to $274 million in the three months ended September 30, 2018 compared to the prior year period, while diluted EPS increased by $0.77 per share to $0.99 per share. For the nine months ended September 30, 2018 , our earnings decreased by $697 million to $60 million compared to the prior year period, while diluted EPS decreased by $2.77 per share to $0.22 per share. The change in EPS included decreases of $(0.09) and $(0.02) in the three months and nine months ended September 30, 2018, respectively, due to the increase in the basic weighted-average number of common shares outstanding, primarily due to the common stock issuances in the first and second quarters of 2018 that we discuss in Note 1 of the Notes to Condensed Consolidated Financial Statements herein. Our results and diluted EPS were impacted by variances discussed in “Segment Results” below and by the items included in the table “Sempra Energy Adjusted Earnings and Adjusted EPS,” also below.

SEGMENT RESULTS

The following section presents earnings (losses) by Sempra Energy segment, as well as Parent and other, and the related discussion of the changes in segment earnings (losses). Throughout the MD&A, our reference to earnings represents earnings attributable to common shares. Variance amounts presented are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise noted, and before NCI, where applicable. As we discuss below in “Changes in Revenues, Costs and Earnings – Income Taxes,” on December 22, 2017, the TCJA was signed into law. The TCJA reduces the U.S. statutory corporate federal income tax rate from 35 percent to 21 percent, effective January 1, 2018. After-tax variances between years assume that amounts in both years were taxed at the 2017 statutory rate.

SEMPRA ENERGY EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
SDG&E	$ 205		$ (28	)	$ 521		$ 276
SoCalGas (1)	(14	)	7		244		268
Sempra Texas Utility	154		—		283		—
Sempra South American Utilities	50		42		140		134
Sempra Mexico	44		66		161		105
Sempra Renewables	34		15		(54	)	49
Sempra LNG & Midstream	16		(4	)	(764	)	24
Parent and other (1)(2)	(215	)	(41	)	(471	)	(99	)
Earnings	$ 274		$ 57		$ 60		$ 757

(1) After preferred dividends.

(2) Includes after-tax interest expense ($89 million and $44 million for the three months ended September 30, 2018 and 2017 , respectively, and $270 million and $125 million for the nine months ended September 30, 2018 and 2017, respectively), intercompany eliminations recorded in consolidation and certain corporate costs.

SDG&E

Earnings of $205 million in the three months ended September 30, 2018 compared to losses of $28 million for the same period in 2017 was primarily due to:

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▪ $208 million charge in 2017 for the write-off of a regulatory asset associated with wildfire costs, which we discuss in Note 11 of the Notes to Condensed Consolidated Financial Statements herein;

▪ $39 million higher earnings from electric transmission operations in 2018, including the annual FERC formulaic rate adjustment; and

▪ $10 million higher CPUC base operating margin authorized for 2018, primarily related to the lower federal income tax rate in 2018; offset by

▪ $14 million decreased CPUC-authorized margin as a result of revised electric distribution seasonality factors in 2018; and

▪ $8 million higher net interest expense, of which $7 million relates to the lower federal income tax rate in 2018.

The increase in earnings of $245 million in the first nine months of 2018 was primarily due to:

▪ $208 million charge in 2017 for the write-off of a regulatory asset associated with wildfire costs;

▪ $50 million higher earnings from electric transmission operations in 2018, including the annual FERC formulaic rate adjustment; and

▪ $33 million higher CPUC base operating margin authorized for 2018, primarily related to the lower federal income tax rate in 2018; offset by

▪ $25 million higher net interest expense, of which $19 million relates to the lower federal income tax rate in 2018;

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

▪ $8 million unfavorable impact due to lower cost of capital in 2018, of which $1 million relates to the lower federal income tax rate in 2018; and

▪ $6 million reimbursement in 2017 of litigation costs associated with the arbitration ruling over the SONGS replacement steam generators, as we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.

SoCalGas

Losses of $14 million in the three months ended September 30, 2018 compared to earnings of $7 million for the same period in 2017 was primarily due to:

▪ $12 million lower CPUC base operating margin authorized for 2018, net of expenses including depreciation. Of this decrease, $7 million relates to the lower federal income tax rate in 2018; and

▪ $5 million higher net interest expense, of which $3 million relates to the lower federal income tax rate in 2018.

The decrease in earnings of $24 million ( 9% ) in the first nine months of 2018 was primarily due to:

▪ $22 million from impacts associated with Aliso Canyon natural gas storage facility litigation;

▪ $15 million unfavorable impact due to lower cost of capital in 2018, of which $3 million relates to the lower federal income tax rate in 2018; and

▪ $13 million higher net interest expense, of which $10 million relates to the lower federal income tax rate in 2018; offset by

▪ $20 million higher CPUC base operating margin authorized for 2018, net of expenses including depreciation. Of this increase, $19 million relates to the lower federal income tax rate in 2018; and

▪ $12 million higher PSEP earnings.

Sempra Texas Utility

Earnings of $154 million and $283 million for the three months and nine months ended September 30, 2018, respectively, represent equity earnings from our investment in Oncor Holdings. We discuss the March 2018 acquisition in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra South American Utilities

Earnings increased by $8 million ( 19% ) in the three months ended September 30, 2018 and by $6 million ( 4% ) in the first nine months of 2018 primarily due to a gain on sale of a hydroelectric power plant development project at Peru.

Sempra Mexico

The decrease in earnings of $22 million ( 33% ) in the three months ended September 30, 2018 was primarily due to:

▪ $63 million unfavorable impact from foreign currency and inflation effects net of foreign currency derivatives effects, comprised of:

◦ in 2018, $73 million unfavorable foreign currency and inflation effects, offset by a $21 million gain from foreign currency derivatives, which we are using to hedge Sempra Mexico’s foreign currency exposure from its controlling interest in IEnova, and

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◦ in 2017, $4 million favorable foreign currency and inflation effects and a $7 million gain from foreign currency derivatives. We discuss these effects below in “Impact of Foreign Currency and Inflation Rates on Results of Operations;” offset by

▪ $14 million earnings attributable to NCI at IEnova in 2018 compared to $33 million in 2017;

▪ $8 million higher pipeline operational earnings, primarily attributable to IEnova’s increased indirect ownership interest in TAG from 25 percent to 50 percent in November 2017; and

▪ $8 million improved operating results at TdM, mainly due to higher power prices.

The increase in earnings of $56 million ( 53% ) in the first nine months of 2018 was primarily due to:

▪ $71 million impairment in 2017, net of a $12 million income tax benefit that has been fully reserved, of the TdM natural gas-fired power plant that was held for sale until June 1, 2018, which we discuss in Note 5 of the Notes to the Condensed Consolidated Financial Statement herein;

▪ $30 million higher pipeline operational earnings, primarily attributable to assets placed in service in the second quarter of 2017 and IEnova’s increased indirect ownership interest in TAG;

▪ $26 million favorable impact from foreign currency and inflation effects net of foreign currency derivatives effects, comprised of:

◦ in 2018, $77 million unfavorable foreign currency and inflation effects, offset by a $27 million gain from foreign currency derivatives, offset by

◦ in 2017, $151 million unfavorable foreign currency and inflation effects, offset by a $75 million gain from foreign currency derivatives;

▪ $18 million improved operating results at TdM, mainly due to higher operating expenses related to major maintenance in the second quarter of 2017 and higher power prices;

▪ $18 million favorable variance in 2018 associated with valuation allowance against TdM’s deferred tax assets; and

▪ $9 million improved operating results at Ecogas, mainly due to new rates approved by CRE and regulated revenues associated with recovery for revised tariffs; offset by

▪ $77 million earnings attributable to NCI at IEnova in 2018 compared to $23 million in 2017 ;

▪ $33 million higher income tax expense in 2018 from the outside basis differences in joint venture investments; and

▪ $32 million lower earnings from equity-related AFUDC, primarily associated with assets placed in service at the end of the first half of 2017, of which $18 million related to cumulative AFUDC recognized in the first quarter of 2017 when regulatory recovery became probable for the Ojinaga and San Isidro pipelines, net of higher equity earnings from AFUDC at the IMG joint venture.

Sempra Renewables

The increase in earnings of $19 million in the three months ended September 30, 2018 was primarily due to:

▪ $10 million lower depreciation as a result of our solar and wind assets that are held for sale; and

▪ $3 million higher pretax losses attributed to NCI .

Losses of $54 million in the first nine months of 2018 compared to earnings of $49 million for the same period in 2017 was primarily due to:

▪ $145 million other-than-temporary impairment of certain U.S. wind equity method investments, as we discuss in Notes 5, 6 and 9 of the Notes to Condensed Consolidated Financial Statements herein; offset by

▪ $34 million higher pretax losses attributed to NCI, including the impact of the TCJA on NCI allocations computed using the HLBV method; and

▪ $10 million lower depreciation as a result of our solar and wind assets that are held for sale.

Sempra LNG & Midstream

Earnings of $16 million in the three months ended September 30, 2018 compared to losses of $4 million for the same period in 2017 was mainly due to higher earnings from midstream activities primarily driven by changes in natural gas prices, and lower depreciation and amortization as a result of natural gas storage assets held for sale.

Losses of $764 million in the first nine months of 2018 compared to earnings of $24 million for the same period in 2017 was primarily due to:

▪ $801 million impairment of certain non-utility natural gas storage assets in the southeast U.S., some of which have been classified as held for sale , as we discuss in Notes 5 and 9 of the Notes to Condensed Consolidated Financial Statements herein;

▪ $34 million settlement proceeds in 2017 from a breach of contract claim against a counterparty in bankruptcy court, of which $28 million related to the charge in 2016 from the permanent release of certain pipeline capacity; and

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▪ $9 million unfavorable adjustment in 2018 to TCJA provisional amounts recorded in 2017 related to the remeasurement of deferred income taxes; offset by

▪ $46 million losses attributable to NCI in 2018 related to the impairment; and

▪ $6 million higher earnings from midstream activities primarily driven by lower depreciation and amortization as a result of natural gas storage assets held for sale.

Parent and Other

The increase in losses of $174 million in the three months ended September 30, 2018 was primarily due to:

▪ $65 million impairment of the RBS Sempra Commodities equity method investment, which we discuss in Note 11 of the Notes to Condensed Consolidated Financial Statements herein;

▪ $50 million increase in net interest expense, of which $15 million relates to the lower tax rate in 2018;

▪ $36 million of mandatory convertible preferred stock dividends;

▪ $10 million income tax expense in 2018 compared to $1 million income tax benefit in 2017; and

▪ $7 million net decrease in investment gains in 2018 on dedicated assets in support of our executive retirement and deferred compensation plans, including higher deferred compensation expense associated with these investments.

The increase in losses of $372 million in the first nine months of 2018 was primarily due to:

▪ $136 million increase in net interest expense, of which $43 million relates to the lower tax rate in 2018;

▪ $89 million of mandatory convertible preferred stock dividends;

▪ $65 million impairment of the RBS Sempra Commodities equity method investment;

▪ $26 million income tax expense in 2018 compared to a $16 million income tax benefit in 2017, which includes $16 million income tax expense in 2018 to adjust TCJA provisional amounts recorded in 2017 and lower income tax benefits as a result of the TCJA in 2018; and

▪ $30 million lower investment gains in 2018 on dedicated assets in support of our executive retirement and deferred compensation plans; and

▪ $22 million higher operating costs retained at Parent; offset by

▪ $14 million lower costs associated with foreign currency derivatives.

ADJUSTED EARNINGS AND ADJUSTED EARNINGS PER COMMON SHARE

We prepare the Condensed Consolidated Financial Statements in conformity with U.S. GAAP. However, management may use earnings and EPS adjusted to exclude certain items (referred to as adjusted earnings and adjusted EPS) internally for financial planning, for analysis of performance and for reporting of results to the board of directors. We may also use adjusted earnings and adjusted EPS when communicating our financial results and earnings outlook to analysts and investors. Adjusted earnings and adjusted EPS are non-GAAP financial measures. Because of the significance and/or nature of the excluded items, management believes that these non-GAAP financial measures provide a meaningful comparison of the performance of business operations to prior and future periods. Non-GAAP financial measures are supplementary information that should be considered in addition to, but not as a substitute for, the information prepared in accordance with U.S. GAAP.

For each period in which a non-GAAP financial measure is used, we provide in the table below a reconciliation of Sempra Energy Adjusted Earnings and Adjusted Diluted EPS to GAAP Earnings and GAAP Diluted EPS, which we consider to be the most directly comparable financial measures calculated in accordance with U.S. GAAP.

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SEMPRA ENERGY ADJUSTED EARNINGS AND ADJUSTED EPS
(Dollars in millions, except per share amounts)
	Pretax amount		Income tax (benefit) expense (1)		Non-controlling interests		Earnings		Diluted EPS
	Three months ended September 30, 2018
Sempra Energy GAAP Earnings							$ 274		$ 0.99
Excluded item:
Impairment of investment in RBS Sempra Commodities	$ 65		$ —		$ —		65		0.24
Sempra Energy Adjusted Earnings							$ 339		$ 1.23
Weighted-average number of shares outstanding, diluted (thousands)									275,907
	Three months ended September 30, 2017
Sempra Energy GAAP Earnings							$ 57		$ 0.22
Excluded item:
Write-off of wildfire regulatory asset	$ 351		$ (143	)	$ —		208		0.82
Sempra Energy Adjusted Earnings							$ 265		$ 1.04
Weighted-average number of shares outstanding, diluted (thousands)									253,364
	Nine months ended September 30, 2018
Sempra Energy GAAP Earnings							$ 60		$ 0.22
Excluded items:
Impairment of investment in RBS Sempra Commodities	$ 65		$ —		$ —		65		0.24
Impairment of non-utility natural gas storage assets	1,300		(499	)	(46	)	755		2.82
Impairment of U.S. wind equity method investments	200		(55	)	—		145		0.54
Impacts associated with Aliso Canyon litigation	1		21		—		22		0.08
Impact from the TCJA	—		25		—		25		0.10
Sempra Energy Adjusted Earnings							$ 1,072		$ 4.00
Weighted-average number of shares outstanding, diluted (thousands)									267,644
	Nine months ended September 30, 2017
Sempra Energy GAAP Earnings							$ 757		$ 2.99
Excluded items:
Write-off of wildfire regulatory asset	$ 351		$ (143	)	$ —		208		0.82
Impairment of TdM assets held for sale	71		—		(24	)	47		0.19
Deferred income tax benefit associated with TdM	—		(8	)	3		(5	)	(0.02	)
Recoveries related to 2016 permanent release of pipeline capacity	(47	)	19		—		(28	)	(0.11	)
Sempra Energy Adjusted Earnings							$ 979		$ 3.87
Weighted-average number of shares outstanding, diluted (thousands)									252,987

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

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For each period in which a non-GAAP financial measure is used, we provide in the tables below a reconciliation of SDG&E and SoCalGas Adjusted Earnings to GAAP (Losses) Earnings, which we consider to be the most directly comparable financial measure calculated in accordance with U.S. GAAP.

SDG&E ADJUSTED EARNINGS
(Dollars in millions)
	Pretax amount	Income tax benefit (1)		(Losses) earnings
	Three months ended September 30, 2017
SDG&E GAAP Losses				$ (28	)
Excluded item:
Write-off of wildfire regulatory asset	$ 351	$ (143	)	208
SDG&E Adjusted Earnings				$ 180
	Nine months ended September 30, 2017
SDG&E GAAP Earnings				$ 276
Excluded item:
Write-off of wildfire regulatory asset	$ 351	$ (143	)	208
SDG&E Adjusted Earnings				$ 484

(1) Income taxes were calculated based on applicable statutory tax rates.

SOCALGAS ADJUSTED EARNINGS
(Dollars in millions)
	Pretax amount	Income tax expense (1)	Earnings
	Nine months ended September 30, 2018
SoCalGas GAAP Earnings			$ 244
Excluded item:
Impacts associated with Aliso Canyon litigation	$ 1	$ 21	22
SoCalGas Adjusted Earnings			$ 266

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

CHANGES IN REVENUES, COSTS AND EARNINGS

This section contains a discussion of the differences between periods in the specific line items of the Condensed Consolidated Statements of Operations for Sempra Energy, SDG&E and SoCalGas.

Utilities Revenues

Our utilities revenues include:

Electric revenues at:

▪ SDG&E

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

Natural gas revenues at:

▪ SDG&E

▪ SoCalGas

▪ Sempra Mexico’s Ecogas

Intercompany revenues included in the separate revenues of each utility are eliminated in the Sempra Energy Consolidated Statements of Operations.

SoCalGas and SDG&E currently operate under a regulatory framework that:

▪ 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

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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’ Gas Cost Incentive Mechanism provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in Note 1 of the Notes to Consolidated Financial Statements and “Item 1. Business – Ratemaking Mechanisms” in the Annual Report.

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

Because changes in SDG&E’s and SoCalGas’ cost of electricity and/or natural gas are substantially recovered in rates, changes in these costs are offset in the changes in revenues, and therefore do not impact earnings. In addition to the changes in cost or market prices, electric or natural gas revenues recorded during a period are impacted by customer billing cycles causing a difference between customer billings and recorded or authorized costs. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 4 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

The California Utilities’ revenues are decoupled from, or not tied to, actual sales volumes. SoCalGas recognizes annual authorized revenue for core natural gas customers using seasonal factors established in the Triennial Cost Allocation Proceeding. Accordingly, a significant portion of SoCalGas’ annual earnings are recognized in the first and fourth quarters of each year. SDG&E’s authorized revenue recognition is also impacted by seasonal factors, resulting in higher earnings in the third quarter when electric loads are typically higher than in the other three quarters of the year. We discuss this decoupling mechanism and its effects further in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

The table below summarizes revenues and cost of sales for our consolidated utilities.

UTILITIES REVENUES AND COST OF SALES
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
Electric revenues:
SDG&E	$ 1,192		$ 1,131		$ 3,014		$ 2,952
Sempra South American Utilities	358		356		1,136		1,108
Eliminations and adjustments (1)	(1	)	(2	)	(3	)	(5	)
Total	1,549		1,485		4,147		4,055
Natural gas revenues:
SoCalGas	802		684		2,700		2,695
SDG&E	107		105		391		399
Sempra Mexico	17		25		58		80
Eliminations and adjustments (1)	(15	)	(22	)	(48	)	(57	)
Total	911		792		3,101		3,117
Total utilities revenues	$ 2,460		$ 2,277		$ 7,248		$ 7,172
Cost of electric fuel and purchased power:
SDG&E	$ 448		$ 417		$ 1,045		$ 994
Sempra South American Utilities	229		233		741		736
Eliminations and adjustments (1)	(2	)	—		(8	)	—
Total	$ 675		$ 650		$ 1,778		$ 1,730
Cost of natural gas:
SoCalGas	$ 224		$ 153		$ 663		$ 740
SDG&E	30		29		110		132
Sempra Mexico	2		16		17		50
Eliminations and adjustments (1)	(1	)	(8	)	(8	)	(19	)
Total	$ 255		$ 190		$ 782		$ 903

(1) Includes eliminations of intercompany activity.

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Electric Revenues and Cost of Electric Fuel and Purchased Power

In the three months ended September 30, 2018 , our electric revenues increased by $64 million ( 4% ) remaining at $1.5 billion , primarily due to:

▪ $61 million increase at SDG&E, which included:

◦ $44 million higher revenues from transmission operations, including the annual FERC formulaic rate adjustment,

◦ $31 million higher cost of electric fuel and purchased power, which we discuss below,

◦ $19 million decrease in charges in 2018 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD, and

◦ $9 million increase in 2018 due to an increase in rates permitted under the attrition mechanism in the 2016 GRC FD, offset by

◦ $19 million decrease due to revised electric distribution seasonality factors in 2018, and

◦ $16 million revenue requirement deferral due to the effect of the TCJA.

Our utilities’ cost of electric fuel and purchased power increased by $25 million ( 4% ) to $675 million in the three months ended September 30, 2018 mainly due to a $31 million increase at SDG&E primarily due to higher electricity market costs, partially offset by lower costs of purchased power from renewable sources due to decreased solar and wind production and from lower capacity contract costs.

In the first nine months of 2018 , our electric revenues increased by $92 million ( 2% ) remaining at $4.1 billion , primarily due to:

▪ $62 million increase at SDG&E, which included:

◦ $51 million higher cost of electric fuel and purchased power, which we discuss below,

◦ $37 million higher revenues from transmission operations, including the annual FERC formulaic rate adjustment,

◦ $26 million decrease in charges in 2018 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD, and

◦ $24 million increase due to 2018 attrition, offset by

◦ $45 million revenue requirement deferral due to the effect of the TCJA,

◦ $25 million revenue requirement deferral related to the SONGS settlement, which is offset by the discontinuation of amortization, and

◦ $10 million lower cost of capital in 2018; and

▪ $28 million increase at Sempra South American Utilities, which included:

◦ $43 million higher rates at Luz del Sur, and

◦ $19 million due to foreign currency exchange rate effects, offset by

◦ $24 million lower volumes at Luz del Sur, primarily driven by weather and the migration of regulated and non-regulated customers to tolling customers, who pay only a tolling fee, and

◦ $17 million lower rates at Chilquinta Energía.

In the first nine months of 2018 , our utilities’ cost of electric fuel and purchased power increased by $48 million ( 3% ) to $1.8 billion , primarily due to:

▪ $51 million increase at SDG&E driven primarily by higher electricity market costs, partially offset by lower costs of purchased power from renewable sources due to decreased solar and wind production and from lower capacity contract costs; and

▪ $5 million increase at Sempra South American Utilities, which included:

◦ $26 million higher prices at Luz del Sur, and

◦ $14 million due to foreign currency exchange rate effects, offset by

◦ $22 million lower volumes at Luz del Sur, and

◦ $16 million lower prices at Chilquinta Energía .

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Natural Gas Revenues and Cost of Natural Gas

The table below summarizes the average cost of natural gas sold by the California Utilities and included in Cost of Natural Gas. The average cost of natural gas sold at each utility is impacted by market prices, as well as transportation, tariff and other charges.

CALIFORNIA UTILITIES AVERAGE COST OF NATURAL GAS
(Dollars per thousand cubic feet)
	Three months ended September 30,		Nine months ended September 30,
	2018	2017	2018	2017
SoCalGas	$ 4.82	$ 3.09	$ 3.17	$ 3.36
SDG&E	4.56	4.14	3.58	4.17

In the three months ended September 30, 2018 , Sempra Energy’s natural gas revenues increased by $119 million ( 15% ) to $911 million primarily due to:

▪ $118 million increase at SoCalGas, which included:

◦ $71 million increase in cost of natural gas sold, which we discuss below,

◦ $30 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are offset in O&M,

◦ $16 million decrease in charges in 2018 associated with tracking the income tax benefit from flow-through items in relation to forecasted amounts in the 2016 GRC FD, and

◦ $13 million increase due to 2018 attrition, offset by

◦ $9 million revenue requirement deferral due to the effect of the TCJA,

◦ $6 million lower revenues from capital projects, including $17 million decrease for advanced metering infrastructure, offset by increases of $3 million for PSEP and $8 million for other capital projects, and

◦ $5 million lower cost of capital in 2018; offset by

▪ $8 million decrease at Sempra Mexico, which included:

◦ $14 million decrease from new regulations that went into effect on March 1, 2018 that no longer allow Ecogas to sell natural gas to high consumption end users (defined by the CRE as customers with annual consumption that exceeds 4,735 MMBtu) and require those end users to procure their natural gas needs from natural gas marketers, including Sempra Mexico’s marketing business, offset by

◦ $7 million increase at Ecogas from a regulatory adjustment to rates charged to end users in 2014 through 2016.

In the three months ended September 30, 2018, our cost of natural gas increased by $65 million ( 34% ) to $255 million primarily due to:

▪ $71 million increase at SoCalGas primarily due to higher average gas prices; offset by

▪ $14 million decrease at Sempra Mexico primarily associated with the lower revenues at Ecogas.

In the first nine months of 2018 , Sempra Energy’s natural gas revenues decreased by $16 million ( 1% ) remaining at $3.1 billion primarily due to:

▪ $22 million decrease at Sempra Mexico, which included;

◦ $29 million lower volumes at Ecogas primarily as a result of the new regulations that went into effect in 2018, offset by

◦ $11 million increase due to higher rates approved by CRE, including $7 million from a regulatory adjustment to rates charged to end users in 2014 through 2016; and

▪ $8 million decrease at SDG&E, which included:

◦ $22 million decrease in cost of natural gas sold, discussed below, offset by

◦ $7 million increase due to 2018 attrition, and

◦ $6 million decrease in charges in 2018 associated with tracking the income tax benefit from flow-through items in relation to forecasted amounts in the 2016 GRC FD; offset by

▪ $5 million increase at SoCalGas, which included:

◦ $90 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are offset in O&M,

◦ $51 million increase due to 2018 attrition, and

◦ $15 million decrease in charges in 2018 associated with tracking the income tax benefit from flow-through items in relation to forecasted amounts in the 2016 GRC FD, offset by

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◦ $77 million decrease in cost of natural gas sold, which we discuss below,

◦ $40 million revenue requirement deferral due to the effect of the TCJA,

◦ $21 million lower cost of capital in 2018, and

◦ $12 million lower revenues from capital projects, including $48 million decrease for advanced metering infrastructure, offset by increases of $13 million for PSEP and $23 million for other capital projects.

In the first nine months of 2018 , our cost of natural gas decreased by $121 million ( 13% ) to $782 million primarily due to:

▪ $77 million decrease at SoCalGas due to $41 million from lower average gas prices and $36 million from lower volumes driven by weather;

▪ $33 million decrease at Sempra Mexico primarily associated with the lower revenues at Ecogas; and

▪ $22 million decrease at SDG&E primarily due to lower average gas prices.

Energy-Related Businesses: Revenues and Cost of Sales

The table below shows revenues and cost of sales for our energy-related businesses.

ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
REVENUES
Sempra South American Utilities	$ 17		$ 20		$ 54		$ 61
Sempra Mexico	393		311		970		793
Sempra Renewables	38		26		103		74
Sempra LNG & Midstream	147		152		330		406
Eliminations and adjustments (1)	(115	)	(107	)	(239	)	(263	)
Total revenues	$ 480		$ 402		$ 1,218		$ 1,071
COST OF SALES (2)
Cost of natural gas, electric fuel and purchased power:
Sempra South American Utilities	$ 4		$ 7		$ 14		$ 15
Sempra Mexico	130		82		252		182
Sempra LNG & Midstream	96		114		216		287
Eliminations and adjustments (1)	(111	)	(106	)	(225	)	(258	)
Total	$ 119		$ 97		$ 257		$ 226
Other cost of sales:
Sempra South American Utilities	$ 13		$ 14		$ 39		$ 41
Sempra Mexico	2		3		7		6
Sempra LNG & Midstream	5		6		14		(37	)
Eliminations and adjustments (1)	(3	)	(2	)	(6	)	(5	)
Total	$ 17		$ 21		$ 54		$ 5

(1) Includes eliminations of intercompany activity.

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

In the three months ended September 30, 2018 , revenues from our energy-related businesses increased by $78 million ( 19% ) to $480 million primarily due to:

▪ $82 million increase at Sempra Mexico primarily due to:

◦ $45 million from the marketing business, primarily due to new regulations that went into effect on March 1, 2018 that require high consumption end users (previously serviced by Ecogas and other natural gas utilities) to procure their natural gas needs from natural gas marketers, including Sempra Mexico’s marketing business, and higher natural gas prices and volumes, and

◦ $30 million at TdM primarily due to higher prices and volumes; offset by

▪ $5 million decrease at Sempra LNG & Midstream primarily due to:

◦ $22 million of costs associated with indemnity payments to Sempra Mexico in 2018. Indemnity payments for 2017 were recorded in Cost of Natural Gas, Electric Fuel and Purchased Power prior to adoption of ASC 606, offset by

◦ $20 million higher natural gas sales to Sempra Mexico primarily due to higher prices and volumes.

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In the three months ended September 30, 2018 , the cost of natural gas, electric fuel and purchased power from our energy-related businesses increased by $22 million ( 23% ) to $119 million primarily due to:

▪ $48 million increase at Sempra Mexico mainly associated with higher revenues from the marketing business as a result of natural gas sales in the distribution market driven by new regulations that went into effect in 2018, and higher natural gas prices and volumes. The increase at Sempra Mexico was also due to higher prices and higher volumes at TdM; offset by

▪ $18 million decrease at Sempra LNG & Midstream primarily due to indemnity payments to Sempra Mexico in 2017, offset by an increase in costs from natural gas marketing activities.

In the first nine months of 2018 , revenues from our energy-related businesses increased by $147 million ( 14% ) to $1.2 billion primarily due to:

▪ $177 million increase at Sempra Mexico primarily due to:

◦ $60 million from the marketing business, primarily due to the new regulations that went into effect in 2018, which we discuss above,

◦ $57 million at TdM primarily due to the plant outage in 2017 as a result of scheduled major maintenance and higher prices,

◦ $37 million primarily due to pipeline assets placed in service in the second quarter of 2017, and

◦ $16 million from operation and maintenance services provided to the TAG joint venture; and

▪ $29 million increase at Sempra Renewables primarily due to solar and wind assets placed in service in the fourth quarter of 2017 and the second quarter of 2018; offset by

▪ $76 million decrease at Sempra LNG & Midstream primarily due to:

◦ $73 million costs associated with indemnity payments to Sempra Mexico in 2018,

◦ $18 million from natural gas marketing activities primarily from changes in natural gas prices, and

◦ $9 million lower revenues from LNG sales to Sempra Mexico and from non-delivery of LNG cargoes due to lower natural gas prices, offset by

◦ $19 million higher natural gas sales to Sempra Mexico primarily due to higher volumes, and

◦ $12 million from LNG sales to Cameron LNG JV in January 2018.

In the first nine months of 2018 , the cost of natural gas, electric fuel and purchased power from our energy-related businesses increased by $31 million ( 14% ) to $257 million primarily due to:

▪ $70 million at Sempra Mexico primarily associated with higher revenues from the marketing business as a result of the new regulations that went into effect in 2018. The increase at Sempra Mexico was also due to higher volumes in 2018 due to the TdM plant outage in 2017; and

▪ $33 million from lower intercompany eliminations of costs primarily associated with sales between Sempra LNG & Midstream to Sempra Mexico; offset by

▪ $71 million decrease at Sempra LNG & Midstream primarily due to indemnity payments to Sempra Mexico in 2017.

In the nine months ended September 30, 2017, other cost of sales included $57 million settlement proceeds received by Sempra LNG & Midstream in May 2017 from a breach of contract claim against a counterparty, of which $47 million is related to the charge in 2016 from permanent release of pipeline capacity.

Operation and Maintenance

Our O&M increased by $60 million (8%) to $819 million in the three months ended September 30, 2018 primarily due to:

▪ $34 million increase at SoCalGas primarily from higher expenses associated with CPUC-authorized refundable programs for which costs incurred are recovered in revenue (refundable program expenses);

▪ $14 million increase at Parent and other primarily from higher retained operating costs ; and

▪ $9 million increase at SDG&E primarily from higher refundable program expenses.

In the first nine months of 2018 , O &M increased by $157 million (7%) to $2.4 billion primarily due to:

▪ $93 million increase at SoCalGas primarily from higher refundable program expenses;

▪ $36 million increase at SDG&E, which included:

◦ $18 million higher refundable program expenses,

◦ $11 million reimbursement of litigation costs in 2017 associated with the arbitration ruling over the SONGS replacement steam generators, as we discuss in Note 10 of the Notes to the Condensed Consolidated Financial Statements herein, and

◦ $11 million higher non-refundable operating costs, including labor, contract services and administrative and support costs; and

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▪ $23 million increase at Parent and other primarily from higher retained operating costs.

Write-off of Wildfire Regulatory Asset

In the third quarter of 2017, SDG&E recorded a $351 million charge for the write-off of a regulatory asset associated with wildfire costs. We discuss this further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

Impairment Losses

In June 2018, Sempra LNG & Midstream recognized a $1.3 billion impairment loss for certain non-utility natural gas storage assets in the southeast U.S., as we discuss in Notes 5 and 9 of the Notes to Condensed Consolidated Financial Statements herein.

In the second quarter of 2017, Sempra Mexico reduced the carrying value of TdM by recognizing a noncash impairment charge of $71 million.

Other Income, Net

As part of our central risk management function, we enter into foreign currency derivatives to hedge Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova. The gains/losses associated with these derivatives are included in Other Income, Net, as described below, and partially mitigate the transactional effects of foreign currency and inflation included in Income Taxes and in earnings from Sempra Mexico’s equity method investments. We discuss policies governing our risk management in “Item 7A. Quantitative and Qualitative Disclosure about Market Risk” in the Annual Report.

Other income, net, increased by $57 million to $97 million in the three months ended September 30, 2018 primarily due to:

▪ $67 million gains in 2018 from interest rate and foreign exchange instruments and foreign currency transactions compared to $5 million losses in 2017 primarily due to:

◦ $33 million foreign currency gain in 2018 compared to a $6 million foreign currency loss in 2017 on a Mexican peso-denominated loan to the IMG joint venture, which is offset in Equity Earnings, and

◦ $24 million higher gains in 2018 on foreign currency derivatives as a result of fluctuation of the Mexican peso.

Other income, net, decreased by $126 million to $196 million in the first nine months of 2018 primarily due to:

▪ $60 million decrease in equity-related AFUDC mainly from completion of pipeline projects at Sempra Mexico in 2017;

▪ $43 million lower gains from interest rate and foreign exchange instruments and foreign currency transactions primarily due to:

◦ $66 million lower gains in 2018 on foreign currency derivatives as a result of fluctuation of the Mexican peso, offset by

◦ $25 million foreign currency gain in 2018 compared to a negligible loss in 2017 on a Mexican peso-denominated loan to the IMG joint venture, which is offset in Equity Earnings; and

▪ $30 million lower investment gains in 2018 on dedicated assets in support of our executive retirement and deferred compensation plans; offset by

▪ $14 million higher non-service component of net periodic benefit credit in 2018, including $13 million at SDG&E and $4 million at SoCalGas.

Interest Income

Interest income increased by $10 million and $50 million in the three months and nine months ended September 30, 2018, respectively, primarily due to interest from a Mexican peso-denominated loan from Sempra Mexico to the IMG joint venture. In the nine months ended September 30, 2018, the increase was also due to i nterest income from short-term investments related to funds raised from the January debt and equity offerings in anticipation of the Merger.

Interest Expense

Interest expense increased by $67 million and $192 million in the three months and nine months ended September 30, 2018, respectively, due to long-term debt issuances, primarily to finance the Merger, and, at Parent and other, an increase in short-term debt borrowings.

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Income Taxes

The table below shows the income tax expense and ETR for Sempra Energy, SDG&E and SoCalGas.

INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
Sempra Energy Consolidated:
Income tax expense (benefit)	$ 167		$ (84	)	$ (127	)	$ 378
Income (loss) before income taxes and equity earnings
of unconsolidated subsidiaries	$ 427		$ 5		$ (15	)	$ 1,154
Equity (losses) earnings, before income tax (1)	(52	)	10		(236	)	31
Pretax income (loss)	$ 375		$ 15		$ (251	)	$ 1,185
Effective income tax rate	45	%	(560	)%	51	%	32 %
SDG&E:
Income tax expense (benefit)	$ 53		$ (72	)	$ 151		$ 72
Income (loss) before income taxes	$ 269		$ (91	)	$ 682		$ 363
Effective income tax rate	20	%	79	%	22	%	20 %
SoCalGas:
Income tax (benefit) expense	$ (7	)	$ (14	)	$ 75		$ 103
(Loss) income before income taxes	$ (21	)	$ (7	)	$ 320		$ 372
Effective income tax rate	33	%	200	%	23	%	28 %

(1) We discuss how we recognize equity earnings in Note 6 of the Notes to Condensed Consolidated Financial Statements herein.

On December 22, 2017, the TCJA was signed into law. The TCJA reduced the U.S. statutory corporate federal income tax rate from 35 percent to 21 percent, effective January 1, 2018. We discuss the TCJA further in Note 1 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 1 and 6 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra Energy Consolidated

Income tax expense in the three months ended September 30, 2018 compared to an income tax benefit for the same period in 2017 was due to higher pretax income in 2018. The pretax income in 2017 included a $351 million ($208 million after tax) write-off of SDG&E’s wildfire regulatory asset, which we discuss in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

The change in income taxes was also impacted by:

▪ $69 million income tax expense in 2018 compared to a $13 million income tax benefit in 2017 from foreign currency and inflation effects; and

▪ $10 million lower favorable impact in 2018 from the resolution of prior years’ income tax items; offset by

▪ $28 million lower income tax expense from the lower U.S. statutory corporate federal income tax rate in 2018.

Income tax benefit in the first nine months of 2018 compared to an income tax expense for the same period in 2017 was due to pretax loss in 2018 compared to pretax income in 2017. Pretax loss in 2018 was impacted by the impairments at our Sempra LNG & Midstream and Sempra Renewables segments, while the pretax income in 2017 was impacted by the write-off of SDG&E’s wildfire regulatory asset.

The change in income taxes was primarily due to:

▪ $131 million income tax benefit in 2018 resulting from the reduced outside basis difference in Sempra LNG & Midstream as a result of the impairment of certain non-utility natural gas storage assets;

▪ $73 million lower income tax expense in 2018 from foreign currency and inflation effects;

▪ $69 million lower income tax expense from the lower U.S. statutory corporate federal income tax rate in 2018; and

▪ $30 million favorable variance in 2018 associated with valuation allowance against deferred tax assets at TdM, including $12 million in the second quarter of 2017 associated with the impairment; offset by

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▪ $25 million income tax expense in 2018 to adjust provisional estimates recorded in 2017 for the effects of TCJA;

▪ $21 million income tax expense in 2018 associated with Aliso Canyon natural gas storage facility litigation;

▪ $22 million lower favorable impact in 2018 from the resolution of prior years’ income tax items; and

▪ $15 million higher income tax expense related to share based compensation.

We discuss the impact of foreign exchange rates and inflation on income taxes below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.” See Note 1 of the Notes to Condensed Consolidated Financial Statements herein and Notes 1 and 6 of the Notes to Consolidated Financial Statements in the Annual Report for further details about our accounting for income taxes and items subject to flow-through treatment.

SDG&E

SDG&E’s income tax expense in the three months ended September 30, 2018 compared to an income tax benefit in the same period in 2017 was due to pretax income in the three-month period in 2018 compared to a pretax loss in the corresponding period in 2017. The pretax loss in 2017 included the $351 million write-off of the wildfire regulatory asset. SDG&E’s income taxes for the three-month period in 2018 were also impacted by $26 million lower income tax expense from the lower U.S. statutory corporate federal income tax rate in 2018, offset by $10 million favorable impact in 2017 from the resolution of prior years’ income tax items.

In addition to the impact from the 2017 write-off of the wildfire regulatory asset, the increase in income tax expense in the first nine months of 2018 was primarily due to:

▪ $18 million favorable impact in 2017 from the resolution of prior years’ income tax items ; offset by

▪ $70 million lower income tax expense from the lower U.S. statutory corporate federal income tax rate in 2018.

SoCalGas

The decrease in SoCalGas’ income tax benefit in the three months ended September 30, 2018 was due to $4 million lower income tax benefit in 2018 from the resolution of prior years’ income tax items.

The decrease in SoCalGas’ income tax expense in the nine months ended September 30, 2018 was primarily due to a lower ETR and lower pretax income. The lower ETR was primarily due to $31 million lower income tax expense from the lower U.S. statutory corporate federal income tax rate in 2018, offset by $21 million income tax expense in 2018 associated with Aliso Canyon natural gas storage facility litigation and $4 million lower income tax benefit in 2018 from the resolution of prior years’ income tax items.

Equity Earnings

In the three months ended September 30, 2018 , equity earnings increased by $61 million to $74 million primarily due to:

▪ $154 million equity earnings, net of income tax, from our investment in Oncor Holdings, which we acquired in March 2018 and which owns an 80.25-percent interest in Oncor; offset by

▪ $65 million impairment of our RBS Sempra Commodities equity method investment; and

▪ $28 million equity losses, net of income tax, at Sempra Mexico in 2018 compared to $2 million equity earnings, net of income tax, in 2017, which includes $33 million foreign currency loss in 2018 compared to a $6 million gain in 2017 at the IMG joint venture on its Mexican peso-denominated loans from its joint venture owners, which is fully offset in Other Income, Net.

In the first nine months of 2018 , equity earnings increased by $24 million to $50 million primarily due to:

▪ $283 million equity earnings, net of income tax, from our investment in Oncor Holdings; and

▪ $2 million equity earnings , net of income tax, at Sempra Mexico in 2018 compared to $7 million equity losses, net of income tax, in 2017 , which included:

◦ $16 million equity losses in 2017 from DEN, which included $6 million of equity losses in DEN’s share of the TAG joint venture prior to IEnova’s acquisition of the remaining 50-percent interest in DEN in November 2017, and

◦ $5 million equity earnings in 2018 at the TAG joint venture, offset by

◦ $5 million equity losses in 2018 compared to $9 million equity earnings in 2017 at the IMG joint venture, which includes a $25 million foreign currency loss in 2018 compared to a negligible gain in 2017 on its Mexican peso-denominated loans from its joint venture owners, which is fully offset in Other Income, Net ; offset by

▪ $200 million other-than-temporary impairment of certain wind equity method investments at Sempra Renewables that are included in our plan of sale; and

▪ $65 million impairment of our RBS Sempra Commodities equity method investment.

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Earnings Attributable to Noncontrolling Interests

In the three months ended September 30, 2018, earnings attributable to NCI decreased by $21 million to $24 million primarily due to lower earnings attributable to NCI at Sempra Mexico in 2018 .

In the first nine months of 2018 , earnings attributable to NCI decreased by $32 million to $12 million primarily due to:

▪ $46 million losses attributable to NCI at Sempra LNG & Midstream in 2018 due to the impairment of certain non-utility natural gas storage assets; and

▪ $34 million higher pretax losses attributed to tax equity investors at Sempra Renewables; offset by

▪ $54 million higher earnings attributable to NCI at Sempra Mexico in 2018.

Mandatory Convertible Preferred Stock Dividends

In the three months and nine months ended September 30, 2018, our board of directors declared dividends of $26 million and $79 million, respectively, on our series A preferred stock and $10 million in each period on our series B preferred stock.

IMPACT OF FOREIGN CURRENCY AND INFLATION RATES ON RESULTS OF OPERATIONS

Because our operations in South America and our natural gas distribution utility in Mexico use their local currency as their functional currency, revenues and expenses are translated into U.S. dollars at average exchange rates for the period for consolidation in Sempra Energy Consolidated’s results of operations. We discuss further the impact of foreign currency and inflation rates on results of operations, including impacts on income taxes and related hedging activity, in “Item 7. MD&A – Impact of Foreign Currency and Inflation Rates on Results of Operations” in the Annual Report.

Foreign Currency Translation

Any difference in average exchange rates used for the translation of income statement activity from year to year can cause a variance in Sempra Energy’s comparative results of operations. Changes in foreign currency translation rates between years impacted our comparative reported results as follows:

TRANSLATION IMPACT FROM CHANGE IN AVERAGE FOREIGN CURRENCY EXCHANGE RATES
(Dollars in millions)
	Third quarter 2018 compared to third quarter 2017		Year-to-date 2018 compared to year-to-date 2017
(Lower) higher earnings from foreign currency translation:
Sempra South American Utilities	$ (2	)	$ 2
Sempra Mexico – Ecogas	(1	)	—
Total	$ (3	)	$ 2

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Foreign Currency Transactional Impacts

Some income statement activities at our foreign operations and their joint ventures are also impacted by transactional gains and losses. A summary of these foreign currency transactional gains and losses included in our reported results is shown in the table below:

TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION
(Dollars in millions)
	Total reported amounts				Transactional gains (losses) included in reported amounts
	Three months ended September 30,
	2018		2017		2018		2017
Other income, net (1)	$ 97		$ 40		$ 67		$ (6	)
Income tax (expense) benefit	(167	)	84		(69	)	13
Equity earnings	74		13		(43	)	1
Net income	334		102		(53	)	6
Earnings attributable to common shares	274		57		(28	)	6
	Nine months ended September 30,
	2018		2017		2018		2017
Other income, net (1)	$ 196		$ 322		$ 63		$ 108
Income tax benefit (expense)	127		(378	)	(63	)	(136	)
Equity earnings	50		26		(41	)	(21	)
Net income	162		802		(50	)	(90	)
Earnings attributable to common shares	60		757		(24	)	(39	)

(1) Total reported amount for the three months and nine months ended September 30, 2017 were adjusted for the retrospective adoption of ASU 2017-07, which we discuss in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

CAPITAL RESOURCES AND LIQUIDITY

OVERVIEW

We expect to meet cash requirements of our operations through cash flows from operations, unrestricted cash and cash equivalents, borrowings under our credit facilities, distributions from our equity method investments, issuances of debt and equity securities, project financing and other equity sales, including partnering in joint ventures.

Our lines of credit provide liquidity and support commercial paper. As we discuss in Note 7 of the Notes to Condensed Consolidated Financial Statements herein, Sempra Energy, Sempra Global and the California Utilities each have five-year revolving credit facilities expiring in 2020. The table below shows the amount of available funds, including available unused credit on these three credit facilities, at September 30, 2018 . Our foreign operations had additional general purpose credit facilities aggregating $1.7 billion , with approximately $1.0 billion available unused credit at September 30, 2018 .

AVAILABLE FUNDS AT SEPTEMBER 30, 2018
(Dollars in millions)
	Sempra Energy Consolidated	SDG&E	SoCalGas
Unrestricted cash and cash equivalents (1)	$ 212	$ 27	$ 4
Available unused credit (2)(3)	3,240	702	750

(1) Amounts at Sempra Energy Consolidated included $161 million held in non-U.S. jurisdictions. We discuss repatriation in “Item 7. MD&A – Changes in Revenues, Costs and Earnings – Income Taxes” in the Annual Report and below in “Impacts of the TCJA.”

(2) Available unused credit is the total available on Sempra Energy’s, Sempra Global’s and the California Utilities’ credit facilities that we discuss in Note 7 of the Notes to Condensed Consolidated Financial Statements herein. Borrowings on the shared line of credit at SDG&E and SoCalGas are limited to $750 million for each utility and a combined total of $1 billion.

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

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Sempra Energy Consolidated

We believe that these available funds, combined with cash flows from operations, distributions from our equity method investments, issuances of debt and equity securities, project financing and other equity sales, including partnering in joint ventures, will be adequate to fund our current operations, including to:

▪ finance capital expenditures

▪ meet liquidity requirements

▪ fund dividends

▪ fund new business or asset acquisitions or start-ups

▪ fund capital contribution requirements

▪ repay maturing long-term debt

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

Sempra Energy and the California Utilities currently have ready access to the long-term debt markets and are not currently constrained in their ability to borrow at reasonable rates. However, changing economic conditions and our financing activities could negatively affect the availability and cost of both short-term and long-term financing. Also, cash flows from operations may be impacted by the timing of commencement and completion of large projects. If cash flows from operations were to be significantly reduced or we were unable to borrow under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety) and investments in new businesses. If these measures were necessary, they would primarily impact our Sempra Mexico, Sempra Renewables and Sempra LNG & Midstream businesses before we would reduce funds necessary for the ongoing needs of our utilities. We also expect to raise funds under our capital rotation plan, including with respect to our agreement with a subsidiary of Con Ed to sell certain of our non-utility U.S. renewables business for $1.54 billion (subject to potential customary adjustments), which we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein and below in “Factors Influencing Future Performance.” However, we plan to use the funds we expect to receive pursuant to this agreement primarily to fund Oncor’s and our agreement to purchase InfraREIT and a 50-percent interest in Sharyland Holdings, LP, respectively, as described below. We monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our intention to maintain our investment-grade credit ratings and capital structure.

We use short-term debt primarily to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures and acquisitions or start-ups. Our corporate short-term, unsecured promissory notes, or commercial paper, were our primary sources of short-term debt funding in the first nine months of 2018. Our California Utilities use short-term debt primarily to meet working capital needs.

We have significant investments in several trusts to provide for future payments of pensions and other postretirement benefits, and nuclear decommissioning. Changes in asset values, which are dependent on the activity in the equity and fixed income markets, have not affected the trust funds’ abilities to make required payments. However, changes in asset values may, along with a number of other factors such as changes to discount rates, assumed rates of return, mortality tables, and regulations, impact funding requirements for pension and other postretirement benefit plans and SDG&E’s NDT. At the California Utilities, funding requirements are generally recoverable in rates. We discuss our employee benefit plans and SDG&E’s NDT, including our investment allocation strategies for assets in these trusts, in Notes 7 and 13, respectively, of the Notes to Consolidated Financial Statements in the Annual Report.

Impacts of the TCJA

In the fourth quarter of 2017, we recorded certain effects of the TCJA, resulting in an increase to income tax expense of $870 million at Sempra Energy Consolidated for the remeasurement of U.S. federal deferred income tax assets and liabilities at the new federal income tax rate of 21 percent, the one-time deemed repatriation tax on cumulative undistributed earnings of U.S.-owned foreign corporations, and the related accrual of incremental U.S. state and foreign withholding taxes on expected future repatriation of our undistributed earnings subject to deemed repatriation. Although there was no cash impact in 2017, these effects represent future tax payments or other cash outflow and, in the case of SDG&E and SoCalGas, the remeasurement of their U.S. federal deferred income tax balances will result in cash outflow primarily for refunds to ratepayers in the future. However, the federal and state income taxes and withholding taxes we accrued allow us to repatriate approximately $4 billion of undistributed non-U.S. earnings without further material tax expense expected. We expect to repatriate approximately $1.6 billion from 2018 to 2022, as cash is generated by our businesses at the local level. We used a portion of our existing NOLs to offset the deemed repatriation tax.

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Certain financial metrics used by credit rating agencies, such as our funds from operations-to-debt percentage, could be negatively impacted as a result of certain provisions of the TCJA and in particular by an anticipated decrease in income tax reimbursement payments to us from SDG&E and SoCalGas due to the reduction in the U.S. statutory corporate income tax rate to 21 percent.

Certain provisions of the TCJA, such as 100-percent expensing of capital expenditures and impacts on utilization of our NOLs, may also influence how we fund capital expenditures, the timing of capital expenditures and possible redeployment of capital through sales or monetization of assets, the timing of repatriation of foreign earnings and the use of equity financing to reduce our future use of debt.

As we discuss in Note 6 of the Notes to Consolidated Financial Statements in the Annual Report and above in “Changes in Revenues, Costs and Earnings – Income Taxes,” our analysis and interpretation of the effects of the TCJA and our assessment of strategies to manage the cash and earnings impacts on our businesses are ongoing.

Loans to/from Affiliates

At September 30, 2018 , Sempra Energy had loans to unconsolidated affiliates totaling $682 million and a loan from an unconsolidated affiliate totaling $36 million , which we discuss in Note 1 of the Notes to Condensed Consolidated Financial Statements herein.

California Utilities

SDG&E and SoCalGas expect that the available unused credit described above, cash flows from operations, and debt issuances will continue to be adequate to fund their respective operations. The California Utilities manage their capital structure and pay dividends when appropriate and as approved by their respective boards of directors.

SDG&E declared common stock dividends of $250 million in the third quarter of 2018, which were paid on October 10, 2018, and declared and paid common stock dividends of $450 million in the year ended December 31, 2017 . SDG&E does not expect to make additional dividend declarations in 2018.

SoCalGas declared $50 million of common stock dividends in the third quarter of 2018, which were paid on October 15, 2018. SoCalGas had not previously declared or paid common stock dividends since 2015. SoCalGas expects that its common stock dividends will continue to be impacted by its ability to maintain its authorized capital structure while managing its capital investment program (approximately $1.4 billion in 2018).

As we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, changes in balancing accounts for significant costs at SDG&E and SoCalGas, particularly a change between over- and undercollected status, may have a significant impact on cash flows, as these changes generally represent the difference between when costs are incurred and when they are ultimately recovered in rates through billings to customers.

SDG&E’s “Commodity – electric” balancing accounts include the following:

▪ Energy Resource Recovery Balancing Account (ERRA) – tracks the difference between amounts billed to customers and the actual cost of electric fuel and purchased power. SDG&E’s ERRA balance was undercollected by $51 million at both September 30, 2018 and December 31, 2017 . The ERRA undercollected balance in 2018 is primarily due to lower than forecasted electric volume in conjunction with seasonalized electric rates. We expect the ERRA balance to slightly increase through the end of the year, mainly due to seasonalized customer consumption.

▪ Electric Distribution Fixed Cost Account (EDFCA) – tracks the difference between the amounts billed to customers and the authorized margin and other costs allocated to electric distribution customers. SDG&E’s EDFCA balance was undercollected by $46 million and $112 million at September 30, 2018 and December 31, 2017 , respectively. The undercollection was driven by lower than forecasted electric volumes sold in 2018 and 2017. We expect the EDFCA balance to increase through the end of the year , mainly due to seasonalized customer consumption and electric rates.

Similarly, SoCalGas’ “Commodity – gas, including transportation” balancing accounts include:

▪ Core Fixed Cost Account (CFCA) – tracks the difference between amounts billed to customers and the authorized margin and other costs allocated to core customers. Because mild weather experienced in 2018 and 2017 resulted in lower natural gas consumption compared to authorized levels, SoCalGas’ CFCA balance was undercollected by $159 million and $164 million at September 30, 2018 and December 31, 2017 , respectively.

SDG&E

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plant for $280 million , subject to adjustments, on or before October 3, 2019 (referred to as the put option), or upon earlier termination of the PPA.

On October 24, 2018, SDG&E and OMEC LLC signed a resource adequacy capacity agreement for a term of almost five years that would start at the expiration of the current tolling agreement in October 2019. The capacity agreement is contingent upon receiving approval from OMEC LLC’s lenders by December 31, 2018, and receiving approval from the CPUC by March 15, 2019. If the resource adequacy capacity agreement is approved, OMEC LLC will waive its right to exercise the put option and, as a result, SDG&E would no longer consolidate Otay Mesa VIE. SDG&E filed for CPUC approval of the resource adequacy capacity agreement in October 2018.

SoCalGas

Aliso Canyon Natural Gas Storage Facility Gas Leak

We provide information on the natural gas leak at the Aliso Canyon natural gas storage facility further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein and in “Factors Influencing Future Performance” below, as well as in “Item 1A. Risk Factors” in the Annual Report. The costs of defending against the related civil and criminal lawsuits and cooperating with related investigations, and any damages, restitution, and civil, administrative and criminal fines, costs and other penalties, if awarded or imposed, as well as costs of mitigating the actual natural gas released, could be significant, and to the extent not covered by insurance (including any costs in excess of applicable policy limits), if there were to be significant delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes, such amounts could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations. Also, higher operating costs and additional capital expenditures incurred by SoCalGas as a result of new laws, orders, rules and regulations arising out of this incident or our responses thereto could be significant and may not be recoverable in customer rates, which may have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

The costs incurred to remediate and stop the Leak and to mitigate local community impacts are significant and may increase, and to the extent not covered by insurance (including any costs in excess of applicable policy limits), if there were to be significant delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes, such amounts could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Sempra Texas Utility

Acquisition of Oncor Holdings

As we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein, on March 9, 2018, Sempra Energy completed transactions resulting in the acquisition of an indirect ownership of an 80.25-percent interest in Oncor for a total purchase price paid of $9.57 billion, including Merger Consideration of $9.45 billion.

As we discuss in Notes 1 and 7 of the Notes to Condensed Consolidated Financial Statements herein, our registered public offerings of common stock (not including shares offered pursuant to forward sale agreements), series A preferred stock and long-term debt completed in January 2018 provided total initial net proceeds of approximately $7.0 billion for partial funding of the Merger Consideration, of which approximately $800 million was used to pay down commercial paper, pending the closing of the Merger.

In March 2018, to fund a portion of the Merger Consideration, we settled approximately $900 million (net of underwriting discounts) of forward sales under the forward sale agreements and raised the remaining portion of the Merger Consideration through issuances of approximately $2.6 billion in commercial paper, with a weighted-average maturity of 47 days and a weighted-average interest rate of 2.2 percent per annum.

Upon closing of the Merger, our funding of the total purchase price was comprised of approximately 31 percent equity and approximately 69 percent debt, which does not include shares that have since been settled and that we expect to settle in our common stock pursuant to forward sale agreements. We intend to ultimately fund the total purchase price with approximately 65 percent equity and approximately 35 percent debt.

In June 2018, we settled approximately $800 million (net of underwriting discounts) of forward sales under the forward sale agreements and used the proceeds from these settlements to repay long-term debt maturing in June 2018 and to repay commercial paper used to fund a portion of the Merger Consideration.

In July 2018, we raised additional net proceeds of approximately $729 million through sales of $566 million of series B preferred stock and $164 million of common stock (not including shares offered pursuant to forward sale agreements).

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The January 2018 and July 2018 forward sale agreements permit us to elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreements. We expect to settle the forward sale agreements entirely by the physical delivery of shares of our common stock in exchange for cash proceeds. As of November 7, 2018, at the initial forward sale price of approximately $105.07 per share in January 2018 and approximately $111.87 per share in July 2018, we expect that the net proceeds from full physical settlement of the remaining forward sale agreements would be approximately $1.8 billion (net of underwriting discounts, but before deducting equity issuance costs, and subject to certain adjustments pursuant to the forward sale agreements). Assuming physical settlement of all outstanding forward sales agreements, we will have achieved funding the total purchase price with approximately 65 percent of equity.

If we do not physically settle all the forward settlement agreements, we may use cash from operations and proceeds from asset sales in place of some equity financing. Some of the equity financing subsequent to the Merger (including proceeds we receive from the settlement of the remaining portion of our forward sale agreements and from other sales of common stock) may be used to repay indebtedness incurred to finance a portion of the total purchase price. If we were to elect cash settlement or net share settlement, the amount of cash proceeds we receive upon settlement would differ, perhaps substantially, or we may not receive any cash proceeds or we may deliver cash (in an amount which could be significant) or shares of our common stock to the forward purchasers. We expect to settle the remaining portion of the forward sale agreements in one or more settlements no later than December 15, 2019, which is the final settlement date under the agreements.

Oncor’s business is capital intensive, and it relies on external financing as a significant source of liquidity for its capital requirements. In the past, Oncor has financed a substantial portion of its cash needs with the proceeds from indebtedness. In the event that Oncor fails to meet its capital requirements, we may be required to make additional investments in Oncor, or if Oncor is unable to access sufficient capital to finance its ongoing needs, we may elect to make additional investments in Oncor which could be substantial and which would reduce the cash available to us for other purposes, could increase our indebtedness and could ultimately materially adversely affect our results of operations, financial condition and prospects. In that regard, our commitments to the PUCT prohibit us from making loans to Oncor. As a result, if Oncor requires additional financing and cannot obtain it from other sources, we may be required to make a capital contribution, rather than a loan, to Oncor.

Commensurate with our ownership interest, we contributed to Oncor $117 million and $112 million in cash on April 23, 2018 and November 2, 2018, respectively.

On July 25, 2018, Oncor’s board of directors declared a dividend of $30 million, of which $24 million is Oncor Holdings’ commensurate share. On August 1, 2018, Oncor Holdings distributed the $24 million to Sempra Energy in the form of a dividend and a tax sharing payment of $9 million and $15 million, respectively. On October 24, 2018, Oncor’s board of directors declared a dividend of $180 million, of which $144 million is Oncor Holdings’ commensurate share. On November 6, 2018, Oncor Holdings distributed the $144 million to Sempra Energy in the form of a dividend and a tax sharing payment of $141 million and $3 million, respectively.

We provide additional discussion regarding the Merger and financing risks below in “Factors Influencing Future Performance,” as well as in Note 18 of the Notes to Consolidated Financial Statements, in “Item 7. MD&A - Factors Influencing Future Performance” and in “Item 1A. Risk Factors” in the Annual Report. We discuss the potential effects of the Merger on our credit ratings in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in the Annual Report.

On October 18, 2018, Sempra Energy committed to make a capital contribution to Oncor for Oncor to fund its acquisition of interests in InfraREIT, which we expect will close in mid-2019. We estimate the capital contribution to be $1,025 million, excluding our share of the approximately $40 million for a management agreement termination fee, as well as other customary transaction costs incurred by InfraREIT that will be borne by Oncor as part of the acquisition. The capital contribution is contingent on the satisfaction of customary conditions, including the substantially simultaneous closing of the transactions contemplated by the InfraREIT Merger Agreement. We discuss these transactions in Note 5 of the Notes to Condensed Consolidated Financial Statements herein and below in “Factors Influencing Future Performance.”

Sempra South American Utilities

We expect to fund operations at Chilquinta Energía and Luz del Sur and dividends at Luz del Sur with available funds, including credit facilities, funds internally generated by those businesses, issuances of corporate bonds and other external borrowings.

Sempra Mexico

We expect to fund operations and dividends at IEnova with available funds, including credit facilities, and funds internally generated by the Sempra Mexico businesses, as well as funds from IEnova’s securities issuances, project financing, interim funding from the parent or affiliates, and partnering in joint ventures.

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IEnova paid $71 million of dividends to minority shareholders in the nine months ended September 30, 2018 and $67 million in the year ended December 31, 2017 .

IEnova’s shareholders approved the formation of a fund for IEnova to repurchase its own shares for a maximum amount of $250 million in 2018. Repurchases shall not exceed IEnova’s total net profits, including retained earnings, as stated in their 2017 financial statements. As of November 7, 2018, IEnova has not repurchased any shares.

Sempra Renewables

As we discuss in Notes 5 and 9 of the Notes to Condensed Consolidated Financial Statements herein and below in “Factors Influencing Future Performance,” on June 25, 2018, our board of directors approved a plan to sell our entire portfolio of U.S. wind and U.S. solar assets. On September 20, 2018, Sempra Renewables, which only has assets in the U.S., entered into an agreement with a subsidiary of Con Ed to sell, for $1.54 billion (subject to potential customary adjustments), all its operating solar assets, one wind generation facility, and its solar and battery storage development projects.

Until completion of the sale, we expect Sempra Renewables to require funds for the development of and investment in electric renewable energy projects. Projects at Sempra Renewables may be financed through a combination of operating cash flow, project financing, funds from the parent, partnering in joint ventures, and other forms of equity sales, including tax equity. The varying costs and structure of these alternative financing sources impact the projects’ returns and their earnings profiles.

Sempra LNG & Midstream

As we discuss in Notes 5 and 9 of the Notes to Condensed Consolidated Financial Statements herein and below in “Factors Influencing Future Performance,” on June 25, 2018, our board of directors approved a plan to sell certain non-utility natural gas storage assets in the southeast U.S. Included in the plan of sale are Mississippi Hub and our 90.9-percent ownership interest in Bay Gas.

We expect Sempra LNG & Midstream to require funding for the development and expansion of its remaining portfolio of projects, which may be financed through a combination of operating cash flow, funding from the parent, project financing and partnering in joint ventures.

Sempra LNG & Midstream, through its interest in Cameron LNG JV, is developing a natural gas liquefaction export facility at the Cameron LNG JV terminal. The majority of the current three-train liquefaction project is project-financed, with most or all of the remainder of the capital requirements to be provided by the project partners, including Sempra Energy, through equity contributions under a joint venture agreement. We expect that our remaining equity requirements to complete the project will be met by a combination of our share of cash generated from each liquefaction train as it comes on line and additional cash contributions. Sempra Energy signed guarantees for 50.2 percent of Cameron LNG JV’s obligations under the financing agreements for a maximum amount of up to $3.9 billion. The project financing and guarantees became effective on October 1, 2014, the effective date of the joint venture formation. The guarantees will terminate upon satisfaction of certain conditions, including all three trains achieving commercial operation and meeting certain operational performance tests. We anticipate that the guarantees will be terminated approximately nine months after all three trains achieve commercial operation.

We discuss Cameron LNG JV and the joint venture financing further in Note 4 of the Notes to Consolidated Financial Statements, in “Item 1A. Risk Factors,” and in “Item 7. MD&A – Factors Influencing Future Performance” in the Annual Report. We also discuss Cameron LNG JV below in “ Factors Influencing Future Performance. ”

CASH FLOWS FROM OPERATING ACTIVITIES

CASH PROVIDED BY OPERATING ACTIVITIES
(Dollars in millions)
	Nine months ended September 30, 2018	2018 change				Nine months ended September 30, 2017 (1)
Sempra Energy Consolidated	$ 2,591	$ (113	)	(4	)%	$ 2,704
SDG&E	1,231	59		5		1,172
SoCalGas	882	(184	)	(17	)	1,066

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

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Sempra Energy Consolidated

Cash provided by operating activities at Sempra Energy decreased in 2018 primarily due to:

▪ $9 million decrease in accounts receivable in 2018 compared to a $167 million decrease in 2017;

▪ $185 million from purchases of GHG allowances in 2018 compared to $62 million in 2017;

▪ $56 million net increase in Insurance Receivable for Aliso Canyon Costs in 2018 compared to a $64 million net decrease in 2017. The $56 million net increase in 2018 primarily includes $126 million of additional accruals, partially offset by $69 million in insurance proceeds received;

▪ $53 million increase in net overcollected regulatory balancing accounts (including long-term amounts included in regulatory assets) at SoCalGas in 2018 compared to a $168 million increase in 2017; and

▪ $103 million lower net income, adjusted for noncash items included in earnings, in 2018 compared to 2017; offset by

▪ $247 million decrease in net undercollected regulatory balancing accounts (including long-term amounts included in regulatory assets) at SDG&E in 2018 compared to a $55 million decrease in 2017;

▪ $30 million decrease in income taxes receivable in 2018 compared to a $74 million increase in 2017;

▪ $91 million increase in deferred revenue requirement due to the TCJA at the California Utilities in 2018;

▪ $57 million net increase in Reserve for Aliso Canyon Costs in 2018 compared to an $11 million net decrease in 2017. The $57 million net increase in 2018 includes $126 million of additional accruals, offset by $69 million of cash paid; and

▪ $54 million change in federal deferred income taxes from the tax sharing agreement with Oncor, as we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein.

SDG&E

Cash provided by operating activities at SDG&E increased in 2018 primarily due to:

▪ $247 million decrease in net undercollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2018 compared to a $55 million decrease in 2017; and

▪ $51 million increase in deferred revenue requirement due to the TCJA in 2018; offset by

▪ $17 million increase in income taxes receivable in 2018 compared to a $66 million decrease in 2017;

▪ $73 million from purchases of GHG allowances in 2018 compared to $8 million in 2017; and

▪ $13 million increase in accounts payable in 2018 compared to a $55 million increase in 2017.

SoCalGas

Cash provided by operating activities at SoCalGas decreased in 2018 primarily due to:

▪ $ 56 million net increase in Insurance Receivable for Aliso Canyon Costs in 2018 compared to a $ 64 million net decrease in 2017. The $ 56 million net increase in 2018 primarily includes $126 million of additional accruals, partially offset by $69 million in insurance proceeds received;

▪ $53 million increase in net overcollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2018 compared to a $168 million increase in 2017;

▪ $196 million decrease in accounts receivable in 2018 compared to a $283 million decrease in 2017; and

▪ $101 million from purchases of GHG allowances in 2018 compared to $50 million in 2017; offset by

▪ $40 million increase in deferred revenue requirement due to the TCJA in 2018;

▪ $19 million decrease in accounts payable in 2018 compared to a $38 million decrease in 2017;

▪ $6 million decrease in income taxes receivable in 2018 compared to a $7 million increase in 2017; and

▪ $27 million increase in inventory in 2018 compared to a $39 million increase in 2017.

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CASH FLOWS FROM INVESTING ACTIVITIES

CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
	Nine months ended September 30, 2018		2018 change		Nine months ended September 30, 2017 (1)
Sempra Energy Consolidated	$ (12,704	)	$ 9,444	290 %	$ (3,260	)
SDG&E	(1,194	)	109	10	(1,085	)
SoCalGas	(1,209	)	176	17	(1,033	)

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

Sempra Energy Consolidated

Cash used in investing activities at Sempra Energy increased in 2018 primarily due to:

▪ $9.57 billion paid, including $9.45 billion of Merger Consideration, for the acquisition of our investment in Oncor Holdings in March 2018, as we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein;

▪ $148 million higher cash contributions to Cameron LNG JV; and

▪ $117 million cash contribution to Oncor; offset by

▪ $237 million lower advances to unconsolidated affiliates;

▪ $65 million decrease in capital expenditures; and

▪ $63 million higher repayments from advances to unconsolidated affiliates.

SDG&E

Cash used in investing activities at SDG&E increased in 2018 primarily due to:

▪ $72 million increase in capital expenditures; and

▪ $31 million repayment received in 2017 from advances to Sempra Energy.

SoCalGas

Cash used in investing activities at SoCalGas increased in 2018 primarily due to:

▪ $94 million increase in capital expenditures; and

▪ $88 million of advances to Sempra Energy in 2018.

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Capital Expenditures

Sempra Energy Consolidated Expenditures for Property, Plant and Equipment

The following table summarizes capital expenditures in 2018 compared to 2017.

EXPENDITURES FOR PROPERTY, PLANT AND EQUIPMENT
(Dollars in millions)
	Nine months ended September 30,
	2018	2017
SDG&E:
Improvements to electric and natural gas distribution systems, including certain pipeline safety
and generation systems	$ 803	$ 723
PSEP	13	39
Improvements to electric transmission systems	370	350
Electric generation plants and equipment	8	10
SoCalGas:
Improvements to natural gas distribution, transmission and storage systems, and for certain
pipeline safety	1,000	859
PSEP	120	144
Advanced metering infrastructure	7	30
Sempra South American Utilities:
Improvements to electric transmission and distribution systems and generation projects in Peru	106	77
Improvements to electric transmission and distribution infrastructure in Chile	55	61
Sempra Mexico:
Construction of the Sonora, Ojinaga and San Isidro pipeline projects	37	151
Construction of other natural gas pipeline and renewables projects, and capital expenditures at Ecogas	218	42
Sempra Renewables:
Construction costs for wind projects	7	115
Construction costs for solar projects	39	246
Sempra LNG & Midstream:
LNG liquefaction development costs and Cameron Interstate Pipeline expansion	17	12
Other	2	4
Parent and other	13	17
Total	$ 2,815	$ 2,880

The amounts and timing of capital expenditures are generally subject to approvals by various regulatory and other governmental and environmental bodies, including the CPUC and the FERC. In 2018, we expect to make capital expenditures and investments of approximately $14.1 billion, an increase from the $13.3 billion summarized in “Item 7. MD&A – Capital Resources and Liquidity” in the Annual Report. The increase is primarily attributable to the gas distribution, gas transmission and gas storage integrity management programs at SDG&E and SoCalGas, the sales and purchase agreement entered into by Sempra South American Utilities, as well as additional capital expenditures planned at Sempra Mexico.

CASH FLOWS FROM FINANCING ACTIVITIES

CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
	Nine months ended September 30, 2018		2018 change	Nine months ended September 30, 2017
Sempra Energy Consolidated	$ 10,045		$ 9,664	$ 381
SDG&E	(22	)	52	(74	)
SoCalGas	323		360	(37	)

Sempra Energy Consolidated

Cash provided by financing activities at Sempra Energy increased in 2018 primarily due to:

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▪ $6.2 billion higher issuances of debt with maturities greater than 90 days, primarily to fund the acquisition of our investment in Oncor Holdings in March 2018, as we discuss in Notes 5 and 7 of the Notes to Condensed Consolidated Financial Statements herein, including:

◦ $5.2 billion for long-term debt ($6.4 billion in 2018 compared to $1.2 billion in 2017), and

◦ $1.0 billion for commercial paper and other short-term debt ($2.2 billion in 2018 compared to $1.2 billion in 2017);

▪ $2.3 billion proceeds, net of $41 million in offering costs, from issuances of common stock in 2018;

▪ $2.3 billion proceeds, net of $41 million in offering costs, from issuances of mandatory convertible preferred stock in 2018; and

▪ $707 million increase in short-term debt in 2018 compared to a $475 million increase in 2017; offset by

▪ $1.1 billion higher payments of debt with maturities greater than 90 days, including:

◦ $633 million for commercial paper and other short-term debt ($1.6 billion in 2018 compared to $973 million in 2017), and

◦ $505 million for long -term debt ($1.4 billion in 2018 compared to $856 million in 2017);

▪ $84 million higher common dividends paid; and

▪ $53 million preferred dividends paid in 2018.

SDG&E

Cash used in financing activities at SDG&E in 2018, decreased primarily due to:

▪ $450 million common dividends paid in 2017; offset by

▪ $205 million decrease in short-term debt in 2018 compared to a $185 million increase in 2017; and

▪ $21 million higher payments of long-term debt in 2018.

SoCalGas

At SoCalGas, financing activities were a source of cash in 2018 compared to a use of cash in 2017, primarily due to:

▪ $949 million issuances of long-term debt in 2018; offset by

▪ $500 million payments of long-term debt in 2018; and

▪ $116 million decrease in short-term debt in 2018 compared to a $36 million decrease in 2017.

COMMITMENTS

As a result of indebtedness we have incurred to fund the acquisition of our investment in Oncor Holdings, which we discuss in Notes 5 and 7 of the Notes to Condensed Consolidated Financial Statements herein, Sempra Energy’s principal contractual commitments have increased by $7.1 billion since December 31, 2017, as summarized in the following table.

INCREASE IN PRINCIPAL CONTRACTUAL COMMITMENTS – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	2018	2019 and 2020	2021 and 2022	Thereafter	Total
Long-term debt	$ —	$ 1,000	$ 700	$ 3,300	$ 5,000
Interest on long-term debt (1)	42	312	238	1,550	2,142
Total	$ 42	$ 1,312	$ 938	$ 4,850	$ 7,142

(1) We calculate expected interest payments using the stated interest rate for fixed-rate obligations. We calculate expected interest payments for variable-rate obligations based on forward rates in effect at September 30, 2018.

We discuss other significant changes to contractual commitments since December 31, 2017 in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

CREDIT RATINGS

The credit ratings of Sempra Energy, SDG&E and SoCalGas remained at investment grade levels during the first nine months of 2018.

On September 5, 2018, S&P downgraded SDG&E’s issuer credit rating to A- from A, SDG&E’s senior secured debt rating to A from A+, and SDG&E’s short-term debt rating to A-2 from A-1. S&P maintained SDG&E’s ratings outlook at negative. On September 6, 2018, Moody’s downgraded the long-term credit ratings of SDG&E, including lowering SDG&E’s issuer rating to A2 from A1 and SDG&E’s senior secured debt rating to Aa3 from Aa2. Moody’s also changed SDG&E’s ratings outlook to stable

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from negative. On September 13, 2018, Fitch Ratings downgraded the credit ratings of SDG&E, including lowering SDG&E’s credit rating to A- from A, SDG&E’s senior secured debt rating to A+ from AA- and SDG&E’s short-term credit rating to F2 from F1, all with a stable outlook.

Also on September 5, 2018, S&P reaffirmed its BBB+ senior unsecured debt rating and BBB+ issuer credit rating for Sempra Energy and its A+ senior secured debt rating and A issuer credit rating for SoCalGas, while affirming its negative outlook of each such rating.

On September 26, 2018, Moody’s confirmed Sempra Energy’s Baa1 issuer and senior unsecured ratings with a negative outlook. The ratings action concluded Moody’s review of Sempra Energy’s ratings initiated on June 25, 2018.

The recent S&P, Moody’s and Fitch Ratings actions with respect to Sempra Energy, SDG&E and SoCalGas, any downgrade of the credit ratings of Sempra Energy or any of its subsidiaries by S&P, Fitch Ratings or Moody’s, or any additional negative outlook on those credit ratings may adversely affect the rates at which borrowings bear interest and the commitment fees on available unused credit, which could make it more costly for us to issue debt securities, to borrow under our credit facilities and to raise certain other types of financing. We provide additional information about our credit ratings at Sempra Energy, SDG&E and SoCalGas in “Item 1A. Risk Factors” below and “Item 7. MD&A – Credit Ratings” in the Annual Report.

Sempra Energy has agreed that, if the credit rating of Oncor’s senior secured debt by any of the three major rating agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT.

FACTORS INFLUENCING FUTURE PERFORMANCE

We discuss various factors that could influence our future performance below and in “Item 7. MD&A – Factors Influencing Future Performance” in the Annual Report. Regarding capital projects, we discuss below significant, new developments to those projects that have occurred in 2018. You should read the information below together with “Item 7. MD&A – Factors Influencing Future Performance” contained in the Annual Report and “Item 1A. Risk Factors” contained herein and in the Annual Report.

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SEMPRA ENERGY

Capital Rotation

On June 28, 2018, we announced that, following a comprehensive strategic review of our businesses and asset portfolio by our board of directors and management over the past year, we intend to sell several energy infrastructure assets, including our entire portfolio of U.S. wind and U.S. solar assets, as well as certain non-utility natural gas storage assets in the southeast U.S. On September 20, 2018, Sempra Renewables entered into an agreement with a subsidiary of Con Ed to sell, for $1.54 billion (subject to potential customary adjustments), all its operating solar assets, one wind generation facility, and its solar and battery storage development projects. We regularly review our portfolio of assets with a view toward allocating capital to those businesses that we believe can further improve shareholder value. We discuss the planned sale further in Notes 5, 6 and 9 of the Notes to Condensed Consolidated Financial Statements herein and below in “Sempra Renewables” and “Sempra LNG & Midstream.”

Shareholder Activism

From time to time, activist shareholders may take certain actions to advance shareholder proposals, or otherwise attempt to effect changes and assert influence on our board of directors or management. On June 11, 2018, Elliott Associates, L.P. and Elliott International, L.P. (collectively, Elliott) and Bluescape Resources Company LLC (Bluescape) disclosed they were collectively holders of an approximately 4.9-percent economic interest in our outstanding common stock as of such date and delivered a letter and accompanying presentation to our board of directors seeking collaboration with them and management to nominate six new directors identified by Elliott and Bluescape and establish a committee of the board of directors to conduct portfolio and operational reviews of our business. On September 18, 2018, we announced that we reached an agreement with Elliott, Bluescape and Cove Key Management, LP that, among other things, added two new board members that were mutually agreed between the parties, and repurposed the board’s LNG Construction and Technology Committee into the LNG and Business Development Committee, which will conduct a comprehensive business review of Sempra Energy. The new committee is comprised of the three existing board members and the two new board members. We are committed to continued constructive communications with all our shareholders and are available to discuss and evaluate ideas from our shareholders on how to maximize long-term value.

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SDG&E

Capital Project Updates

We summarize below updates regarding certain major capital projects at SDG&E.

CAPITAL PROJECTS – SDG&E — Project description		Estimated capital cost (in millions)		Status
Electric Vehicle Charging
§	January 2017 application, pursuant to SB 350, to perform various activities and make investments in support of residential electric vehicle charging.	$ 50	§	In January 2018, received approval for six priority projects at $20 million.
			§	In May 2018, the CPUC issued a final decision, revising the proposal to five years, providing rebates to customers for 60,000 installations, reducing the estimated capital cost from $302 million to a total of $30 million. The O&M costs are estimated to be $151 million. SDG&E will implement the modified program subject to establishing an acceptable shareholder incentive mechanism.
§	January 2018 application, pursuant to SB 350, to make investments to support medium-duty and high-duty electric vehicles with an estimated implementation cost of $34 million of O&M.	$ 121	§	Application seeking approval of settlement filed on November 5, 2018; draft decision expected in the first half of 2019.
Energy Storage Projects
§	April 2017 application to procure up to 70 MW of utility-owned energy storage to provide local capacity.	Not disclosed	§	Final decision issued in May 2018 approving the project.
§	February 2018 application, pursuant to AB 2868, to make investments to accelerate the widespread deployment of distributed energy storage systems. SDG&E’s application requests approval of 100 MW of utility-owned energy storage.	$ 161	§	Application pending; draft decision expected in the first half of 2019.
Utility Billing and Customer Information Systems Software
§	April 2017 application to replace the software, with an estimated implementation cost of $76 million of O&M.	$ 222	§	Final decision issued in August 2018 authorizing SDG&E to proceed with the project and have it in service by as early as January 2021.

Risks Associated with Wildfires

With respect to claims related to the 2007 wildfires, based on the trial court’s ruling that inverse condemnation claims would apply, we were subject to a strict liability standard. However, we were denied recovery by the CPUC of our non-FERC related wildfire costs. SDG&E applied to the CPUC for rehearing of its decision on January 2, 2018. On July 12, 2018, the CPUC adopted a decision denying the rehearing requests filed by SDG&E and other parties. On August 3, 2018, SDG&E filed an appeal with the California Court of Appeal seeking to reverse the CPUC’s decision. The filing also asked the court to direct the CPUC to award SDG&E recovery for payments made to settle inverse condemnation and limit any reasonableness review to the amounts of those payments. On September 7, 2018, the CPUC and two other parties filed responses with the California Court of Appeal requesting that SDG&E’s petition be denied. SDG&E submitted a reply to those parties on October 2, 2018 and is now awaiting court action on the appeal. The California Court of Appeal is not required to hear this appeal, in which case, SDG&E’s recourse would be to appeal this decision to the California Supreme Court.

Insurance coverage for wildfires has significantly increased in cost and may become prohibitively expensive, may be disputed by the insurers, or may become unavailable. Moreover, any insurance proceeds we receive for wildfire events may be insufficient to cover our losses or liabilities due to the inability to procure a sufficient amount of insurance and/or the existence of limitations, exclusions, high deductibles, failure to comply with procedural requirements, and other factors, which could materially adversely affect SDG&E’s and Sempra Energy’s business, financial condition, results of operations, cash flows and/or prospects.

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Senate Bill 100

On September 10, 2018, the Governor of California signed into law SB 100, which establishes the 100 Percent Clean Energy Act of 2018 (the Act). The Act accelerates the Renewables Portfolio Standard (RPS) of 50 percent from 2030 to December 31, 2026 and increases the RPS from 50 percent to 60 percent by 2030, and creates the policy of meeting all the State of California’s retail electricity supply with a mix of RPS-eligible and zero-carbon resources by December 31, 2045, for a total of 100 percent clean energy. The Act includes stipulations that this policy not increase carbon emissions elsewhere in the western grid and not allow resource shuffling. Further, the Act requires that the CPUC, CEC, CARB and other state agencies incorporate this policy into all relevant planning.

Potential Impacts of Community Choice Aggregation and Direct Access

SDG&E’s bundled customers have the option to purchase the commodity of electricity from alternate suppliers under defined programs, including CCA and DA. Several local political jurisdictions, including the City of San Diego and other municipalities, are considering or implementing a CCA, which could result in the departure of more than half of SDG&E’s bundled load. SDG&E, PG&E and Edison pursued proposals with the CPUC in 2017 and 2018 to revise the existing cost allocation mechanisms to help ensure compliance with state law intended to protect bundled customers.

In October 2018, the CPUC issued a final decision that revises the current Power Charge Indifference Adjustment (PCIA) framework by adopting several refinements to better ensure ratepayer indifference, as required by law, and directing the utilities to implement updated PCIA rates effective January 1, 2019 using the adopted methodology. The final decision revises the benchmarks used to calculate the PCIA and directs the future implementation of an annual true-up mechanism to ensure that ratepayer indifference is maintained. The decision also removes existing restrictions on recovering certain costs through the PCIA, including the ability to recover the above-market costs of resources that have been in the utility’s portfolio for more than 10 years and certain legacy utility-owned generation resources. We believe these PCIA changes should help ensure that cost allocations result in ratepayer indifference and comply with the law. However, further refinements to the PCIA may be required to help ensure that the remaining bundled customers do not experience any cost increase as a result of departing customers.

See “Item 7. MD&A – Factors Influencing Future Performance” in the Annual Report for additional discussion on CCA and DA.

Other SDG&E Matters

See “Item 7. MD&A – Factors Influencing Future Performance” in the Annual Report for a discussion about:

▪ Electric Rate Reform – California Assembly Bill 327

▪ Renewable Energy Procurement

▪ Clean Energy and Pollution Reduction Act – California SB 350

▪ SONGS

SOCALGAS

Capital Project Update

We summarize below an update regarding a capital project at SoCalGas.

CAPITAL PROJECT – SOCALGAS — Project description	Estimated capital cost (in millions)			Status
San Joaquin Valley OIR
§	In 2014, AB 2672 was signed into law providing increased access to energy for disadvantaged communities in the San Joaquin Valley.	$ 85	§	Decision expected in the first half of 2019.
§	In January 2018, submitted pilot proposals for seven communities to extend existing pipelines, install gas service to each household, and replace existing propane appliances with new, energy efficient natural gas appliances, with an estimated implementation cost of $14 million of O&M.

Aliso Canyon Natural Gas Storage Facility Gas Leak

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In October 2015, SoCalGas discovered a leak at one of its injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility (the Leak) located in Los Angeles County, which SoCalGas has operated as a natural gas storage facility since 1972. SoCalGas worked closely with several of the world’s leading experts to stop the Leak. In February 2016, DOGGR confirmed that the well was permanently sealed.

See Note 11 of the Notes to Condensed Consolidated Financial Statements herein for discussions of the following related to the Leak:

▪ Local Community Mitigation Efforts

▪ Insurance

▪ Governmental Investigations and Civil and Criminal Litigation

▪ Regulatory Proceedings

▪ Governmental Orders and Additional Regulation

The costs incurred to remediate and stop the Leak and to mitigate local community impacts have been significant and may increase, and we may be subject to potential significant damages, restitution, and civil, administrative and criminal fines, penalties and other costs. In addition, the costs of defending against civil and criminal lawsuits, cooperating with investigations, and any damages, restitution, and civil, administrative and criminal fines, penalties and other costs, if awarded or imposed, as well as the costs of mitigating the actual natural gas released, could be significant. To the extent any of these costs are not covered by insurance (including any costs in excess of applicable policy limits), if there were to be significant delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes, such amounts could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Cost Estimates and Accounting Impact

At September 30, 2018 , SoCalGas’ best estimate of costs related to the Leak was $1,039 million (the cost estimate), which includes $1,012 million of costs recovered or probable of recovery from insurance. Approximately 55 percent of the cost estimate is for the temporary relocation program (including cleaning costs and certain labor costs). The remaining portion of the cost estimate includes legal costs incurred to defend litigation, the estimated costs to settle certain actions, the estimated cost of the root cause analysis being conducted by an independent third party, efforts to control the well, the costs to mitigate the actual natural gas released, the value of lost gas, and other costs. SoCalGas adjusts its estimated total liability associated with the Leak as additional information becomes available. A substantial portion of the cost estimate has been paid and $161 million is accrued as Reserve for Aliso Canyon Costs as of September 30, 2018 on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets for amounts expected to be paid after September 30, 2018 .

As of September 30, 2018 , we recorded the expected recovery of the cost estimate related to the Leak of $474 million as Insurance Receivable for Aliso Canyon Costs on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets. This amount is net of insurance retentions and $538 million of insurance proceeds we received through September 30, 2018 related to portions of the cost estimate described above, including temporary relocation costs, control-of-well expenses, legal costs and lost gas. If we were to conclude that this receivable or a portion of it is no longer probable of recovery from insurers, some or all of this receivable would be charged against earnings, which could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

As described in “Governmental Investigations and Civil and Criminal Litigation” in Note 11 of the Notes to Condensed Consolidated Financial Statements herein, the actions seek compensatory, statutory and punitive damages, restitution, and civil, administrative and criminal fines, penalties and other costs, which except for the amounts paid or estimated to settle certain actions, are not included in the cost estimate as it is not possible at this time to predict the outcome of these actions or reasonably estimate the amount of damages, restitution or civil, administrative or criminal fines, penalties or other costs that may be imposed. The recorded amounts above also do not include the costs to clean additional homes pursuant to the directive issued by DPH, future legal costs necessary to defend litigation, and other potential costs that we currently do not anticipate incurring or that we cannot reasonably estimate. Furthermore, the cost estimate does not include certain other costs expensed by Sempra Energy through September 30, 2018 associated with defending against shareholder derivative lawsuits.

Natural Gas Storage Operations and Reliability

Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and heating needs in the winter. The Aliso Canyon natural gas storage facility, with a storage capacity of 86 Bcf (which represents 63 percent of SoCalGas’ natural gas storage inventory capacity), is the largest SoCalGas storage facility and an important element of SoCalGas’ delivery system. Beginning October 25, 2015, pursuant to orders by DOGGR and the Governor of the State of California, and in accordance with SB 380, SoCalGas suspended injection of natural

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gas into the Aliso Canyon natural gas storage facility.

Having completed the steps outlined by state agencies to safely begin injections at the Aliso Canyon natural gas storage facility, as of July 31, 2017, SoCalGas resumed limited injections. The CPUC has issued a series of directives to SoCalGas establishing the range of working gas to be maintained in the Aliso Canyon natural gas storage facility to help ensure safety and reliability for the region and just and reasonable rates in California, the most recent of which, issued July 2, 2018, directed SoCalGas to maintain up to 34 Bcf of working gas.

If the Aliso Canyon natural gas storage facility were to be permanently closed, or if future cash flows were otherwise insufficient to recover its carrying value, it could result in an impairment of the facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At September 30, 2018 , the Aliso Canyon natural gas storage facility had a net book value of $696 million , including $285 million for the recently completed construction of a new compressor station. Any significant impairment of this asset could have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations for the period in which it is recorded. Higher operating costs and additional capital expenditures incurred by SoCalGas may not be recoverable in customer rates, and could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Increased Regulation

PHMSA, DOGGR, SCAQMD, EPA and CARB each commenced separate rulemaking proceedings to adopt further regulations covering natural gas storage facilities and injection wells. See “Item 7. MD&A – Factors Influencing Future Performance” in the Annual Report for a discussion of the following regulations:

▪ SB 380

▪ SB 888

▪ Additional Safety Enhancements

PIPES Act of 2016

In June 2016, the “Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016” or the “PIPES Act of 2016” was enacted. In December 2016, PHMSA published an interim final rule pursuant to the PIPES Act of 2016 that revises the federal pipeline safety regulations relating to underground natural gas storage facilities. The interim final rule incorporates consensus safety measures for the construction, maintenance, risk-management, and integrity-management procedures for natural gas storage. SoCalGas has developed and implemented policies and procedures to demonstrate compliance with the standards.

Higher operating costs and additional capital expenditures incurred by SoCalGas as a result of new laws, orders, rules and regulations arising out of the Aliso Canyon natural gas storage facility incident or our responses thereto could be significant and may not be recoverable in customer rates, and SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations may be materially adversely affected by any such new laws, orders, rules and regulations.

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CALIFORNIA UTILITIES – JOINT MATTERS

Capital Project Updates

We summarize below updates regarding joint capital projects of the California Utilities.

JOINT CAPITAL PROJECTS – CALIFORNIA UTILITIES — Project description	Estimated capital cost (in millions)			Status
Line 1600 Test or Replacement Project
§	September 2015 application seeking authority to recover the estimated $633 million cost of the PSRP, a PSEP project, involving construction of an approximately 47-mile, 36-inch natural gas transmission pipeline in San Diego County.	$ 671	§	Submitted a plan in September 2018 to the CPUC to address Line 1600 PSEP requirements by replacing 37 miles of Line 1600 predominately in populated areas and testing 13 miles of Line 1600 in rural areas.
§	In June 2018, the CPUC issued a final decision denying the application for the PSRP and instead directed SDG&E and SoCalGas to submit a hydrostatic test or replacement plan for the existing Line 1600 in its present corridor.		§	A response from the CPUC is expected in the fourth quarter of 2018.
§	Estimated O&M implementation cost of $45 million and cost to retire portions of Line 1600 of $14 million at SDG&E.
Mobile Home Park Utility Upgrade Program
§	May 2017 application filed with the CPUC to convert an additional 20 percent of eligible units to direct utility service, for a total of 30 percent of mobile homes.	$ 471	§	September 2017 CPUC resolution approved an extension of the pilot program through the earlier of 2019 or the issuance of a CPUC decision on pending applications, while also allowing an increase from 10 percent to 15 percent of mobile homes to be converted.
		to
§	Estimated implementation cost of $2 million of O&M at SDG&E and $3 million to $4 million of O&M at SoCalGas.	$ 508	§	In April 2018, the CPUC opened an OIR to evaluate the Mobile Home Park Program and determine if it should be extended beyond the initial three-year pilot to a permanent program, and if extended, to adopt programmatic modifications.
			§	In October 2018, a proposed decision was issued that would dismiss the May 2017 application, without prejudice, because the issues are subsumed by the OIR.
			§	A final decision in the OIR is expected in the fourth quarter of 2019.
Leak Abatement Compliance Program
§	CPUC OIR to implement new rules and procedures in response to SB 1371 to promote reductions in natural gas leakage and implement annual emissions reporting requirements and leak management practices.	$ 115	§	Advice letter submitted in March 2018 requesting authority to implement the first two years (2018-2019) of a 12-year leak abatement program. The advice letter outlined the recovery mechanism and the proposed activities for the Leak Abatement Compliance Program.
§	Estimated O&M implementation costs through 2020 of $124 million at SoCalGas and $7 million at SDG&E.		§	Supplemental filing submitted on July 31, 2018 to update the overall implementation cost estimate through 2020.
			§	Resolution approving the compliance plans and cost forecast adopted in October 2018.

Natural Gas Pipeline Operations Safety Assessments

As we discuss in “Item 7. MD&A – Factors Influencing Future Performance” in the Annual Report, s ince 2011, the California Utilities have incurred costs related to the implementation of the CPUC’s directives to test or replace natural gas transmission pipelines that do not have sufficient documentation of a pressure test and to address retrofitting pipelines to allow for in-line inspection tools and, where appropriate, automated or remote controlled shut-off valves (referred to as PSEP).

As shown in the table below, SoCalGas and SDG&E have made significant pipeline safety investments under the PSEP program, and SoCalGas expects to continue making significant investments as approved through various regulatory proceedings. SDG&E’s PSEP program was substantially completed in 2017, with the exception of Line 1600, which we discuss in the table above. Both

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utilities have filed joint applications or plan to file future applications with the CPUC for review of the PSEP project costs as follows :

PIPELINE SAFETY ENHANCEMENT PLAN – REASONABLENESS REVIEW SUMMARY
(Dollars in millions)
	2011 through September 30, 2018
	Total invested (1)	CPUC review completed (2)	CPUC review pending (3)	2018 and future applications (4)(5)
Sempra Energy Consolidated:
Capital	$ 1,628	$ 8	$ 163	$ 1,457
Operation and maintenance	195	25	63	107
Total	$ 1,823	$ 33	$ 226	$ 1,564
SoCalGas:
Capital	$ 1,268	$ 8	$ 149	$ 1,111
Operation and maintenance	186	25	62	99
Total	$ 1,454	$ 33	$ 211	$ 1,210
SDG&E:
Capital	$ 360	$ —	$ 14	$ 346
Operation and maintenance	9	—	1	8
Total	$ 369	$ —	$ 15	$ 354

(1) Excludes disallowed costs through September 30, 2018 of $7 million at SoCalGas and $4 million at SDG&E for pressure testing or replacing pipelines installed between January 1, 1956 and July 1, 1961. Also excludes $38 million of costs incurred for the PSRP/Line 1600.

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

(3) Reasonableness Review Application for completed projects totaling $195 million filed in September 2016. Also includes approximately $31 million of pre-engineering costs incurred to support projects under development and submitted as part of the Forecast Application filed in March 2017. Both decisions are expected in the first quarter of 2019.

(4) Authorized to recover in rates 50 percent of the balances recorded in the PSEP Phase 1 balancing accounts each year, subject to refund.

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

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Senate Bill 901

On September 21, 2018, the Governor of California signed into law SB 901, which includes a number of measures primarily intended to address certain wildfire risks relevant to consumers and utilities and guidelines for the CPUC to determine whether utilities acted reasonably in order to recover costs related to wildfires. Among other things, SB 901 also contains provisions for utility issuance of recovery bonds with respect to certain wildfire costs, subject to CPUC approval, wildfire mitigation plans, and creation of a commission to explore establishment of a fund and options for cost socialization with respect to catastrophic wildfires associated with utility infrastructure. The provisions of SB 901 are applicable to 2017 wildfire costs incurred by utilities, if any, and wildfire events occurring on or after January 1, 2019. Accordingly, we do not expect SB 901 to impact SDG&E's recovery of its 2007 wildfire costs or wildfires that occur between the date of this report and January 1, 2019.

The CPUC initiated an OIR in October 2018 to implement the provisions of SB 901 related to electric utility wildfire mitigation plans. The OIR will provide guidance on the form and content of the initial wildfire mitigation plans, provide a venue for review of the initial plans, and develop and refine the content of and process for review and implementation of wildfire mitigation plans to be filed in future years. The schedule for the proceeding will be established at a later date. However, we anticipate that electric utilities will file their proposed wildfire mitigation plans by the end of February 2019 and the CPUC will approve the final plans in mid-2019. The scope of the OIR is limited to only the wildfire mitigation plans required by SB 901 and does not include cost recovery. Pursuant to SB 901, the CPUC shall authorize each utility to establish a memorandum account to track the costs incurred to implement the plan. The costs recorded to the memorandum account shall be incremental to the utility’s authorized recovery and reviewed as part of the utility’s next GRC proceeding.

SB 901 did not change the doctrine of inverse condemnation, which imposes strict liability on a utility (meaning that the utility may be found liable regardless of fault) whose equipment is determined to be a cause of a fire. In their recent ratings actions for SDG&E, which we discuss above in “Capital Resources and Liquidity – Credit Ratings,” each of Moody’s, Fitch Ratings and S&P indicated that the rating downgrades reflected the failure of SB 901 to address the longer-term risks associated with inverse condemnation.

Separately, SB 901, together with draft guidance from the CPUC, also provides that electric and gas corporations, such as SDG&E and SoCalGas, shall no longer recover compensation (including salary, bonus, benefits or other consideration paid) of certain senior officers from ratepayers; rather, such compensation shall be a shareholder expense. In October 2018, the CPUC published a draft resolution ordering memorandum accounts to be established to track such compensation costs.

SEMPRA TEXAS UTILITY

Acquisition of Oncor Holdings

On March 9, 2018, we completed the acquisition of an indirect, 100-percent interest in Oncor Holdings, which owns an 80.25-percent interest in Oncor, and other EFH assets and liabilities unrelated to Oncor. Due to ring-fencing measures, existing governance mechanisms and commitments in effect following the Merger, we are prevented from having the power to direct the significant activities of Oncor Holdings and Oncor. As a result, we account for our 100-percent ownership interest in Oncor Holdings as an equity method investment, which is included in our newly formed reportable segment, Sempra Texas Utility. Certain other assets and liabilities unrelated to Oncor acquired in connection with the Merger were subsumed within our parent organization. We discuss this Merger and the related financing in Notes 1, 5, 6 and 7 of the Notes to Condensed Consolidated Financial Statements herein, and above in “Item 2. MD&A – Capital Resources and Liquidity.”

Oncor Performance

The success of the Merger will depend, in part, on the ability of Oncor to successfully execute its business strategy, including several objectives that are capital intensive, and to respond to challenges in the electric utility industry. If Oncor is not able to achieve these objectives, is not able to achieve these objectives on a timely basis, or otherwise fails to perform in accordance with our expectations, the anticipated benefits of the Merger may not be realized fully or at all and the Merger may materially adversely affect the results of operations, financial condition and prospects of Sempra Energy.

Absence of Control

In accordance with the ring-fencing measures, existing governance mechanisms and commitments we made in connection with the Merger, we are subject to the following restrictions, among others:

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

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

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

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

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

▪ Without the prior approval of the PUCT, neither Sempra Energy nor any of its affiliates (excluding Oncor) will incur, guarantee or pledge assets in respect of any indebtedness that is dependent on the revenues of Oncor in more than a proportionate degree than the other revenues of Sempra Energy or on the stock of Oncor, and there will be no debt at Sempra Texas Holdings Corp. or Sempra Texas Intermediate Holding Company LLC at any time;

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

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

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

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

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

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

As a result of these ring-fencing measures, governance mechanisms and commitments, we do not control Oncor Holdings or Oncor, and we have limited ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important corporate issues and actions. We have limited representation on the Oncor Holdings and Oncor boards of directors, which are controlled by independent directors. In addition, we are not allowed to make loans to Oncor Holdings or Oncor. The existence of these ring-fencing measures and other limitations may increase our costs of financing. Further, the Oncor directors have considerable autonomy and, as described in our commitments, have a duty to act in the best interest of Oncor consistent with the approved ring-fence and Delaware law, which may be contrary to our best interests or be in opposition to our preferred strategic direction for Oncor. To the extent that they take actions that are not in our interests, the financial condition, results of operations and prospects of Sempra Energy may be materially adversely affected.

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Key Personnel at Oncor

If, despite efforts to retain certain key personnel at Oncor, any key personnel depart or fail to continue employment as a result of the Merger, the loss of the services of such personnel and their experience and knowledge could adversely affect Oncor’s results of operations, financial condition and prospects and the successful ongoing operation of its business, which could also have a material adverse effect on the results of operations, financial condition and prospects of Sempra Energy.

Pending Acquisitions

On October 18, 2018, Oncor entered into the InfraREIT Merger Agreement, whereby Oncor will acquire a 100 percent interest in InfraREIT and InfraREIT Partners for approximately $1,275 million, plus approximately $40 million for a management agreement termination fee, as well as other customary transaction costs incurred by InfraREIT that will be borne by Oncor as part of the acquisition. In addition, the transaction includes InfraREIT’s outstanding debt, which as of September 30, 2018 was approximately $945 million. Also on October 18, 2018, Oncor entered into the Asset Exchange Agreement, whereby SDTS will accept and assume certain electricity transmission and distribution-related assets and liabilities of SU in exchange for certain SDTS assets. Immediately prior to completing the exchange, SDTS will become a wholly owned, indirect subsidiary of InfraREIT Partners.

On October 18, 2018, Sempra Energy entered into the Securities Purchase Agreement, whereby Sempra Texas Utilities Holdings I, LLC will acquire 50 percent of the economic interest in Sharyland Holdings, LP for approximately $98 million, subject to customary closing adjustments. In connection with and prior to the consummation of the Securities Purchase Agreement, Sharyland Holdings, LP will own 100 percent of the membership interests in SU and SU will convert into a limited liability company, expected to be named Sharyland Utilities, LLC. Upon consummation of the Securities Purchase Agreement, Sempra Texas Utilities Holdings I, LLC will indirectly own and account for its 50 percent interest in Sharyland Utilities, LLC as an equity method investment.

Consummation of these transactions is subject to the satisfaction of various closing conditions, including the substantially concurrent consummation of these transactions. These transactions also require approval by the PUCT and the FERC and expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, as well as the satisfaction of other regulatory requirements, certain lender consents and other customary closing conditions. In addition, the acquisition of InfraREIT requires the approval of the InfraREIT stockholders, is subject to a standard go shop process whereby InfraREIT can, among other things, solicit offers that may be superior to the terms of the transaction that Oncor has proposed, and the approval of the Committee on Foreign Investment in the United States. We expect that the transactions will close in mid-2019. There can be no assurance that Oncor and Sempra Energy will derive the anticipated benefits from these acquisitions.

We discuss these transactions further in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

Oncor will fund its acquisition of interests in InfraREIT from capital contributions from Sempra Energy and certain indirect equity holders of TTI, proportionate to Sempra Energy’s and TTI’s respective ownership interests in Oncor. We plan to fund our approximately $1,025 million share of the contribution to Oncor (excluding Sempra Energy’s share of approximately $40 million for a management agreement termination fee, as well as other customary transaction costs incurred by InfraREIT that will be borne by Oncor as part of the acquisition) and purchase the 50-percent interest in Sharyland Holdings, LP by utilizing a portion of the anticipated proceeds of $1.54 billion (subject to potential customary adjustments) from the pending sale of certain of our non-utility U.S. renewables business to a subsidiary of Con Ed that we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein .

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SEMPRA SOUTH AMERICAN UTILITIES

Luz del Sur - Potential Impact from Tolling Customers

Luz del Sur is an electric distribution utility that provides electric services, including the supply of electricity, to regulated and non-regulated customers. Non-regulated customers consist of free and tolling customers. Luz del Sur supplies electricity to its customers from power purchased from generators under long-term, take-or-pay PPAs. A free customer has the option of purchasing electricity directly from Luz del Sur, while paying fees to Luz del Sur for generation, transmission (primary and secondary) and distribution services, or choosing to become a tolling customer. A tolling customer purchases electricity from alternative suppliers and pays only a tolling fee to Luz del Sur for secondary transmission and distribution. To the extent customers have the right to and choose to become tolling customers, Luz del Sur may be exposed to stranded costs related to capacity charges under its long-term, take-or-pay PPAs. We discuss Luz del Sur’s customers and demand in “Item 1. Business” in the Annual Report.

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SEMPRA MEXICO

Capital Project Updates

We summarize below updates regarding major capital projects at Sempra Mexico.

CAPITAL PROJECTS – SEMPRA MEXICO — Project description	Estimated capital cost (in millions)			Status
Terminals at Port of Veracruz, Puebla and Mexico City
§	Awarded a 20-year concession in July 2017 to build and operate a marine terminal in the Port of Veracruz in Mexico for the receipt, storage and delivery of liquid fuels.	$ 170	§	Expected completion of marine terminal: third quarter of 2019
§	Working capacity of 1.4 million barrels of gasoline, diesel and jet fuel to supply the central region of Mexico.		§	Planned storage capacity increased to 2.1 million barrels.
§	IEnova will also build and operate two storage terminals located near Puebla and Mexico City with storage capacities of 500,000 and 800,000 barrels, respectively.	$ 145	§	Expected completion of two inland storage terminals: third quarter of 2019
§	Entered into three, long-term, U.S. dollar-denominated terminal services agreements in July 2017 with Valero Energy for the full capacity of the marine terminal and the two inland storage terminals.		§	Storage capacities at the Puebla and Mexico City terminals have been reallocated to 650,000 barrels each.
§	Pursuant to these agreements, Valero Energy has the option to purchase a 50-percent interest in each of the three terminals after commencement of commercial operations, subject to approval by the Port of Veracruz, COFECE, the CRE and other regulatory bodies.
Don Diego Solar Complex
§	Plan to develop, construct and operate a 125-MW photovoltaic project located in Sonora, Mexico.	$ 130	§	Estimated completion: second half of 2019
§	In February 2018, entered into a 15-year, U.S. dollar-denominated PPA with various subsidiaries of El Puerto de Liverpool, S.A.B. de C.V. for a portion of the capacity.
Baja Refinados Terminal
§	Plan to develop, construct and operate a liquid fuels marine storage terminal within the La Jovita Energy Center, located 23 km north of Ensenada, Baja California, Mexico.	$ 130	§	Estimated completion: second half of 2020
§	Capacity of 1 million barrels of hydrocarbons, primarily gasoline and diesel, to increase fuel supply capacity and reliability in Baja California.
§	Fully contracted under two, long-term, U.S. dollar-denominated contracts for the receipt, storage and delivery of hydrocarbons with Chevron and BP. Chevron and BP have the option to acquire 20 percent and 25 percent, respectively, of the equity of the terminal after commercial operations begin.
Topolobampo Port Administration Terminal
§	Plan to develop, construct and operate a marine terminal for the receipt and storage of hydrocarbons, petroleum, petrochemicals and other liquids.	$ 150	§	Estimated completion: fourth quarter of 2020
§	Storage capacity of 1 million barrels, mainly for diesel and gasoline, to increase fuel supply sources and reliability in Sinaloa.
§	Fully contracted under 15-year and 10-year, U.S. dollar-denominated contracts for the receipt, storage and delivery of hydrocarbons with Chevron and a subsidiary of Marathon Petroleum Corporation, respectively. Both contracts have the potential to be extended to 20 years. Chevron has the option to acquire up to 25 percent of the equity of the terminal after commercial operations begin.

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CAPITAL PROJECTS – SEMPRA MEXICO (CONTINUED) — Project description	Our share of estimated capital cost (in millions)			Status
Sur de Texas-Tuxpan Marine Pipeline
§	IMG was awarded the right to build, own and operate the natural gas marine pipeline in June 2016 by the CFE.	$ 942	§	Estimated completion: fourth quarter of 2018
§	Sempra Mexico has a 40-percent interest in IMG, a joint venture with TransCanada, which owns the remaining 60-percent interest.		§	Our share of the estimated capital cost increased from $840 million to $942 million, commensurate with our ownership interest.
§	Natural gas transportation services agreement for a 25-year term, denominated in U.S. dollars.
Manzanillo Terminal
§	Plan to develop, construct and operate a marine terminal for the receipt, storage and delivery of refined products in Manzanillo, Colima.	$ 102	§	Estimated completion: fourth quarter of 2020
		to
§	Entered into a long-term, U.S. dollar-denominated agreement with Trafigura Mexico, S.A. de C.V. for 740,000 barrels of the terminal’s initial storage capacity.	$ 165
§	Estimated storage capacity of 1.48 million barrels, with opportunities for expansion.
§	51-percent equity interest in joint venture, with option to increase ownership interest up to 82.5 percent.

Energía Costa Azul LNG Terminal

As we discuss in “Item 7. MD&A – Factors Influencing Future Performance” in the Annual Report, Sempra LNG & Midstream and IEnova are developing a proposed natural gas liquefaction project at IEnova’s existing regasification terminal at ECA. The proposed liquefaction facility project is being developed to provide buyers with direct access to west coast LNG supplies.

On November 2, 2018, Sempra Energy and TOTAL S.A. entered into an MOU that provides the framework for cooperation for the development of the potential ECA liquefaction-export project and the potential Cameron LNG expansion project that we describe below in “Sempra LNG & Midstream – Proposed Additional Cameron Liquefaction Expansion.” The MOU contemplates TOTAL S.A. potentially contracting for up to approximately 9 Mtpa of LNG offtake across these two development projects and provides TOTAL S.A. the option to acquire an equity interest in the proposed ECA LNG liquefaction facility project, though the ultimate participation by TOTAL S.A. remains subject to finalization of definitive agreements, among other factors.

In early November 2018, Sempra LNG & Midstream and IEnova signed Heads of Agreements with affiliates of TOTAL S.A., Mitsui & Co., Ltd. and Tokyo Gas Co., Ltd. for Phase 1 of the potential ECA liquefaction-export project. We expect ECA LNG Phase 1 to be a single train liquefaction facility located adjacent to the existing LNG receipt terminal with a capacity of approximately 2.4 Mtpa of LNG for export to global markets. Each Heads of Agreement for ECA LNG Phase 1 contemplates the parties negotiating definitive 20-year LNG sales and purchase agreements for the purchase of approximately 0.8 Mtpa of LNG from the ECA LNG facility, but does not obligate the parties to ultimately execute any agreements.

In June 2018, we selected a TechnipFMC plc and Kiewit Corporation partnership as the EPC contractor for the proposed ECA LNG liquefaction facility project. The TechnipFMC-Kiewit partnership is to perform the engineering, planning and related activities necessary to prepare, negotiate and finalize a definitive EPC contract for the project.

The ultimate participation of TOTAL S.A., Mitsui & Co., Ltd. and Tokyo Gas Co., Ltd. in the potential ECA LNG project as contemplated by the Heads of Agreements remains subject to finalization of definitive agreements, among other factors. The development of the ECA LNG Phase 1 and Phase 2 projects is subject to numerous risks and uncertainties, including obtaining binding customer commitments, the receipt of a number of permits and regulatory approvals; obtaining financing; negotiating and completing suitable commercial agreements, including a definitive EPC contract, joint venture agreements, LNG sales agreements and gas supply and transportation agreements; reaching a final investment decision; and other factors associated with this potential investment. For a discussion of these risks, see “Item 1A. Risk Factors” in the Annual Report.

Termoeléctrica de Mexicali

On June 1, 2018, management formalized its decision not to sell TdM, and the assets and liabilities that were previously classified as held for sale were reclassified as held and used, as we discuss in Note 5 of the Notes to Condensed Consolidated Financial

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Statements herein.

SEMPRA RENEWABLES

As we discuss in Notes 5, 6 and 9 of the Notes to Condensed Consolidated Financial Statements herein, on June 25, 2018, our board of directors approved a plan to sell all our U.S. wind assets and U.S. solar assets, including our wholly and jointly owned operating facilities and projects in development in our Sempra Renewables reportable segment (the Renewables Sale). These wholly and jointly owned assets include operating wind and solar facilities with a total generating capacity of 1,335 MW and 1,262 MW, respectively. As a result, in June 2018, we classified these Sempra Renewables consolidated assets and liabilities as held for sale. Although Sempra Renewables’ wind and solar equity method investments are included in the plan of sale, we continue to classify them as Other Investments. Because of our expectation of a shorter holding period as a result of this plan of sale, we evaluated the recoverability of the carrying amounts of our wind and solar equity method investments and concluded there was an other-than-temporary impairment on certain of our wind equity method investments totaling $200 million ($145 million after tax), which we recorded in Equity Earnings on the Sempra Energy Condensed Consolidated Statement of Operations in the nine months ended September 30, 2018.

As we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein, on September 20, 2018, Sempra Renewables entered into an agreement to sell all its operating solar assets, its solar and battery storage development projects and one wind generation facility to a subsidiary of Con Ed for $1.54 billion, subject to customary adjustments and various closing conditions. We expect the transaction to close in the fourth quarter of 2018.

We continue to actively pursue the sale of the remaining wind generation assets, which we expect to complete in 2019. Successful completion and the timing of the sale of these assets is subject to a number of risks and uncertainties, including identifying one or more acceptable buyers, negotiating and entering into definitive sales agreements for the remaining wind generation assets that we expect to be subject to various customary closing conditions, and obtaining the necessary third-party approvals and consents.

Sempra Renewables’ financial performance is primarily a function of the solar and wind power generated by its assets. Power generation from these assets depends on solar and wind resource levels, weather conditions, and Sempra Renewables’ ability to maintain equipment performance. The demand for renewable energy is impacted by various market factors, most notably state mandated requirements for utilities to deliver a portion of total energy load from renewable energy sources. Additionally, the phase out or extension of U.S. federal income tax incentives, primarily investment tax credits and production tax credits, and grant programs could significantly impact future renewable energy resource availability and investment decisions. Imposition by the U.S. government of ad valorem tariffs, import quotas or other import restrictions related to solar panels could materially adversely affect Sempra Renewables’ business, investment decisions and the demand for renewable energy in the U.S. Any adverse impact on Sempra Renewables or its assets from the foregoing may also adversely impact the valuation of the assets pursuant to the Renewables Sale by potential buyers, which may in turn impair our ability to successfully complete our sale of those assets.

We may be unable to implement the Renewables Sale in whole or in part, in which case we would not realize the anticipated benefits. Alternatively, even if implemented, the Renewables Sale may not result in the anticipated benefits to our business, results of operations and financial condition in a timely manner or at all. Further, we could experience unexpected delays, business disruptions resulting from supporting this initiative during and following completion of these activities, decreased productivity, adverse effects on employee morale and employee turnover as a result of such initiative, any of which may impair our ability to achieve anticipated results or otherwise harm our business, results of operations and financial condition.

Capital Project Updates

We summarize below the completion of a solar project in 2018 at Sempra Renewables.

CAPITAL PROJECT COMPLETED IN 2018 – SEMPRA RENEWABLES
Project description
Great Valley Solar Project
§	Capable of producing up to 200 MW of solar power, located in Fresno County, California, acquired in July 2017.	§	Commercial operation dates and corresponding contracted energy sales commenced in four phases. Three phases commenced in the fourth quarter of 2017 and the final phase commenced in April 2018.
§	Fully contracted under four PPAs with an average contract term of 18 years.

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SEMPRA LNG & MIDSTREAM

Cameron LNG JV Three-Train Liquefaction Project

Construction on the current three-train liquefaction project began in the second half of 2014 under an EPC contract with a joint venture between CB&I, LLC (as assignee of CB&I Shaw Constructors, Inc.), a wholly owned subsidiary of McDermott International, Inc., and Chiyoda International Corporation, a wholly owned subsidiary of Chiyoda Corporation.

The total cost of the integrated Cameron LNG JV facility, including the cost of the original facility that was contributed to the joint venture interest during construction, financing costs and required reserves, was estimated to be approximately $10 billion at the time of our final investment decision.

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 TOTAL 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.

Sempra Energy and the project partners executed project financing documents for senior secured debt in an 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 up to $3.9 billion. The project financing and completion guarantees became effective on October 1, 2014, and the guarantees 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.

Large-scale construction projects like the design, development and construction of the Cameron LNG JV liquefaction facility involve numerous risks and uncertainties, including among others, the potential for unforeseen engineering challenges, substantial construction delays and increased costs. Cameron LNG JV has a turnkey EPC contract, and if the contractor becomes unwilling or unable to perform according to the terms and timetable of the EPC contract, the project could face substantial construction delays and potentially significantly increased costs. If the contractor’s delays or failures are serious enough to cause the contractor to default under the EPC contract, such default could result in Cameron LNG JV’s engagement of a substitute contractor, which would cause further delays.

During the course of construction of large projects like Cameron LNG, contractors often assert that they are owed additional compensation, schedule extensions, and/or accelerated payments. Cameron LNG JV received information from the EPC contractor claiming it was owed additional amounts beyond the contract value and entitled to schedule extensions, including as a result of the impacts of Hurricane Harvey and other events impacting the project. In December 2017, Cameron LNG JV entered into a Settlement Agreement with the EPC contractor that settled claims by the EPC contractor that it was owed additional compensation beyond the original contract price and that it was entitled to schedule extensions under the EPC contract. The Settlement Agreement resolves all of the EPC contractor’s known and unknown claims prior to December 17, 2017 and became effective in January 2018.

Under the Settlement Agreement, Cameron LNG JV has agreed to additional contract and bonus payments. These payments are subject to the EPC contractor’s achievement of certain milestones, including milestones aligned to the completion of commissioning the LNG trains. In addition, the bonus payments become payable only if the EPC contractor satisfies certain additional milestones. The Settlement Agreement waives schedule-related liquidated damages related to the original contract schedule and reestablishes the start dates for such liquidated damages according to the settlement schedule.

Based on a number of factors, we continue to believe it is reasonable to expect that all three trains at the Cameron LNG JV liquefaction facility will begin producing LNG in 2019 and that Cameron LNG JV will start generating earnings in 2019. These factors include, among others, the terms of the Settlement Agreement, the project schedules received from the EPC contractor, Cameron LNG JV’s own review of the project schedules, the assumptions underlying such schedules, the EPC contractor’s progress to date, the remaining work to be performed, and the inherent risks in constructing and testing facilities such as the Cameron LNG JV liquefaction facility. For a discussion of the Cameron LNG JV and of these risks and other risks relating to the development of the Cameron LNG JV liquefaction project that could adversely affect our future performance, see Note 4 of the Notes to Consolidated Financial Statements and “Item 1A. Risk Factors” in the Annual Report.

These delays in the project and the terms of the Settlement Agreement increased the total estimated cost of the integrated Cameron LNG facility above the approximately $10 billion estimated cost; however, the estimated increase is expected to be within the project contingency established by the Cameron LNG JV at the time of the final investment decision for the project in August 2014 and is not expected to be material to Sempra Energy.

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Proposed Additional Cameron Liquefaction Expansion

Cameron LNG JV has received the major permits and FTA and non-FTA approvals necessary to expand the current configuration of the Cameron LNG JV liquefaction project from the current three liquefaction trains under construction. The proposed expansion project includes up to two additional liquefaction trains, capable of increasing LNG production capacity by approximately 9 Mtpa to 10 Mtpa, and up to two additional full containment LNG storage tanks (one of which was permitted with the original three-train project).

Under the Cameron LNG JV financing agreements, expansion of the Cameron LNG JV facilities beyond the first three trains is subject to certain restrictions and conditions, including among others, timing restrictions on expansion of the project unless appropriate prior consent is obtained from lenders. Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all the partners, including with respect to the equity investment obligation of each partner. Discussions among the partners have been taking place regarding how an expansion may be structured. On July 13, 2018, TOTAL S.A. acquired Engie S.A.’s interest in the Cameron LNG JV. On November 2, 2018, Sempra Energy and TOTAL S.A. entered into an MOU that provides the framework for cooperation for the development of the potential Cameron LNG expansion project and the potential ECA liquefaction-export project that we describe above in “Sempra Mexico – Energía Costa Azul LNG Terminal.” The MOU contemplates TOTAL S.A. potentially contracting for up to approximately 9 Mtpa of LNG offtake across these two development projects, though the ultimate participation of TOTAL S.A. remains subject to finalization of definitive agreements, among other factors. We expect that discussions on the potential expansion will continue among all the Cameron LNG JV members. There can be no assurance that a mutually agreeable expansion structure will be agreed unanimously by among the Cameron LNG JV members, which if not accomplished in a timely manner, could materially and adversely impact the development of the expansion project. In light of this, we are unable to predict when we and/or Cameron LNG JV might be able to move forward on this expansion project.

The expansion of the Cameron LNG JV facilities beyond the first three trains is subject to a number of risks and uncertainties, including amending the Cameron LNG JV agreement among the partners, obtaining binding customer commitments, completing the required commercial agreements, securing and maintaining all necessary permits, approvals and consents, obtaining financing, reaching a final investment decision among the Cameron LNG JV partners, and other factors associated with the potential investment. See “Item 1A. Risk Factors” in the Annual Report.

Other LNG Liquefaction Development

Design, regulatory and commercial activities are ongoing for potential LNG liquefaction developments at our Port Arthur, Texas site and at Sempra Mexico’s ECA facility. For these development projects, we have met with potential customers and determined there is an interest in long-term contracts for LNG supplies beginning in the 2022 to 2025 time frame.

Port Arthur

As we discuss in “Item 7. MD&A – Factors Influencing Future Performance” in the Annual Report, Sempra LNG & Midstream is currently seeking authorization to site, construct and operate the proposed Port Arthur LNG natural gas liquefaction and export facility in Port Arthur, Texas.

The proposed project is designed to include:

▪ two natural gas liquefaction trains with a nameplate capacity of 13.5 Mtpa of LNG and an expected export capability of approximately 11 Mtpa of LNG or 1.6 Bcf per day;

▪ up to 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 February 2018, Sempra LNG & Midstream and Woodside Petroleum Ltd. entered into a project development agreement, which replaced a prior agreement between the parties, for the joint development of the proposed Port Arthur LNG liquefaction project. On July 19, 2018, the parties terminated the project development agreement. As a result, Woodside Petroleum Ltd. is no longer participating in the development of the Port Arthur LNG liquefaction project.

In June 2018, we selected Bechtel as the EPC contractor for the proposed Port Arthur LNG liquefaction project. Bechtel is to perform the engineering, execution planning and related activities necessary to prepare, negotiate and finalize a definitive EPC contract for the project. Additionally, on June 26, 2018, Polish Oil & Gas Company and Port Arthur LNG entered into a preliminary agreement relating to the terms of a potential 20-year contract for the sales and purchase of 2 Mtpa of LNG per year.

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The current arrangements with Bechtel and Polish Oil & Gas Company do not commit any party to enter into a definitive EPC contract or LNG sales and purchase agreement or otherwise participate in the project.

On August 31, 2018, the FERC issued a Notice of Schedule that sets January 31, 2019 as the planned completion date of the final environmental impact statement for the siting, construction and operation of the proposed Port Arthur LNG liquefaction project. On September 28, 2018, the FERC issued the draft environmental impact statement for the project.

Development of the Port Arthur LNG liquefaction project is subject to a number of risks and uncertainties, including obtaining customer commitments, completing the required commercial agreements, such as joint venture agreements, LNG sales agreements, gas supply agreements and an EPC contract; completing construction contracts; securing all necessary permits and approvals; obtaining financing and incentives; reaching a final investment decision; and other factors associated with the potential investment. See “Item 1A. Risk Factors” in the Annual Report.

Energía Costa Azul

We further discuss Sempra LNG & Midstream’s participation in potential LNG liquefaction development at Sempra Mexico’s ECA facility above in “Sempra Mexico – Energía Costa Azul LNG Terminal.”

Natural Gas Storage Assets

As we discuss in Notes 5 and 9 of the Notes to Condensed Consolidated Financial Statements herein, on June 25, 2018, our board of directors approved a plan to sell Mississippi Hub and our 90.9-percent ownership interest in Bay Gas. Because of the plan of sale, we classified these non-utility natural gas storage assets as held for sale and recorded them at the lower of their carrying values and fair values less costs to sell. We also own other U.S. midstream assets that are not included in the plan of sale, primarily comprised of our 75.4-percent interest in LA Storage, a salt cavern development project in Cameron Parish, Louisiana. The LA Storage project also includes an existing 23.3-mile pipeline header system that is not currently contracted. Our inability to secure customer contracts that would support further investment in LA Storage has led us to conclude that the full carrying value of these other U.S. midstream assets may not be recoverable. Because of these events, in June 2018, we recognized an impairment charge on the non-utility natural gas storage assets and other U.S. midstream assets totaling $1.3 billion ($755 million after tax and noncontrolling interests) in Impairment Losses.

We are actively pursuing the sale of Sempra LNG & Midstream’s non-utility natural gas storage assets (the Midstream Sale), which we expect to complete in 2019. Successful completion and the timing of such sale are subject to a number of risks and uncertainties, including identifying one or more acceptable buyers, negotiating and entering into definitive agreements for the Midstream Sale that are expected to be subject to various customary closing conditions, and obtaining the necessary third-party approvals and consents.

We may be unable to implement the Midstream Sale in whole or in part, in which case we would not realize the anticipated benefits. Alternatively, even if implemented, the Midstream Sale may not result in the anticipated benefits to our business, results of operations and financial condition in a timely manner or at all. Further, we could experience unexpected delays, business disruptions resulting from supporting this initiative during and following completion of these activities, decreased productivity, adverse effects on employee morale and employee turnover as a result of such initiative, any of which may impair our ability to achieve anticipated results or otherwise harm our business, results of operations and financial condition.

RBS SEMPRA COMMODITIES

For a discussion about RBS Sempra Commodities, see “Item 7. MD&A – Factors Influencing Future Performance” in the Annual Report and in Notes 5, 6 and 11 of the Notes to Condensed Consolidated Financial Statements herein.

OTHER SEMPRA ENERGY MATTERS

For a discussion about Other Sempra Energy Matters, see “Item 7. MD&A – Factors Influencing Future Performance” in the Annual Report.

LITIGATION

We describe legal proceedings that could adversely affect our future performance in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We view certain accounting policies as critical because their application is the most relevant, judgmental, and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates. We discuss these accounting policies in “Item 7. MD&A” in the Annual Report.

We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We follow the same accounting policies for interim reporting purposes.

NEW ACCOUNTING STANDARDS

We discuss the relevant pronouncements that have recently been issued or become effective and have had or may have an impact on our financial statements and/or disclosures in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We provide disclosure regarding derivative activity in Note 8 of the Notes to Condensed Consolidated Financial Statements herein. We discuss our market risk and risk policies in detail in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in the Annual Report.

INTEREST RATE RISK

The table below shows the nominal amount of long-term debt:

NOMINAL AMOUNT OF LONG-TERM DEBT (1)
(Dollars in millions)
	September 30, 2018			December 31, 2017
	Sempra Energy Consolidated	SDG&E	SoCalGas	Sempra Energy Consolidated	SDG&E	SoCalGas
California Utilities fixed-rate	$ 8,523	$ 5,064	$ 3,459	$ 7,877	$ 4,868	$ 3,009
Other fixed-rate	11,590	—	—	8,367	—	—
Other variable-rate	2,105	—	—	907	—	—

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

Interest rate risk sensitivity analysis measures interest rate risk by calculating the estimated changes in earnings that would result from a hypothetical change in market interest rates. If interest rates increased or decreased by 10 percent on all of Sempra Energy’s effective variable-rate, long-term debt at September 30, 2018 , the change in earnings over the next 12-month period ended September 30, 2019 would be approximately $4 million. These hypothetical changes in earnings are based on our long-term debt position after the effect of interest rate swaps.

FOREIGN CURRENCY AND INFLATION RATE RISK

We discuss our foreign currency and inflation exposure in “Item 2. MD&A – Impact of Foreign Currency and Inflation Rates on Results of Operations” herein and in “Item 7. MD&A – Impact of Foreign Currency and Inflation Rates on Results of Operations” in the Annual Report. At September 30, 2018 , there were no significant changes to our exposure to foreign currency rate risk since December 31, 2017.

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ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Sempra Energy, SDG&E and SoCalGas have designed and maintain disclosure controls and procedures to ensure that information required to be disclosed in their respective reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and is accumulated and communicated to the management of each company, including each respective principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, the management of each company recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives; therefore, the management of each company applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures.

Under the supervision and with the participation of management, including the principal executive officers and principal financial officers of Sempra Energy, SDG&E and SoCalGas, each company evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of September 30, 2018 , the end of the period covered by this report. Based on these evaluations, the principal executive officers and principal financial officers of Sempra Energy, SDG&E and SoCalGas concluded that their respective company’s disclosure controls and procedures were effective at the reasonable assurance level.

INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in the companies’ internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the companies’ internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses) except for the matters 1) described in Notes 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 13 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, or 2) referred to in “Item 2. MD&A” herein or in “Item 7. MD&A” in the Annual Report.

ITEM 1A. RISK FACTORS

When evaluating our company and its subsidiaries, we urge you to carefully consider the risks and other information in this Quarterly Report on Form 10-Q, including the factors discussed in “Item 2. MD&A – Factors Influencing Future Performance,” the risk factors disclosed in “Item 1A. Risk Factors” in the Annual Report and in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, as well as the risk factors discussed below. Except as set forth below and in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, there have been no material changes from the risk factors as previously disclosed in the Annual Report. Any of the risks and other information discussed in this Quarterly Report on Form 10-Q or any of the risks disclosed in “Item 1A. Risk Factors” in the Annual Report or in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, as well as additional risks and uncertainties not currently known to us or that we currently deem immaterial, could materially and adversely affect our businesses, cash flows, results of operations, financial condition, prospects and/or the trading prices of our securities or those of our subsidiaries.

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Risks Related to Sempra Energy Subsidiaries

Certain credit rating agencies may downgrade our credit ratings or place those ratings on negative outlook.

Credit rating agencies routinely evaluate Sempra Energy, SDG&E and SoCalGas, and their long-term and short-term debt ratings are based on a number of factors, including the perceived supportiveness of the regulatory environment affecting utility operations, ability to generate cash flows, level of indebtedness, overall financial strength and the status of certain capital projects, as well as factors beyond our control, such as tax reform, the state of the economy and our industry generally.

Moody’s, Fitch Ratings and S&P have increasingly focused on the risk of an increase in California wildfires and the current California regulatory environment, which may prohibit California utilities from recovering any uninsured wildfire costs as a result of California’s doctrine of inverse condemnation. The inverse condemnation doctrine imposes strict liability on a utility (meaning that the utility may be found liable regardless of fault) whose equipment is determined to be a cause of a fire. In that regard, the California Legislature approved SB 901 on August 31, 2018, which was signed into law by the Governor of California on September 21, 2018. Although SB 901 includes a number of regulatory measures intended to address certain wildfire risks relevant to consumers and utilities and whether utilities acted reasonably in order to recover costs related to wildfires, it does not change the doctrine of inverse condemnation. Among other things, SB 901 also contained provisions for utility issuance of recovery bonds with respect to certain wildfire costs, subject to CPUC approval, wildfire mitigation plans, and creation of a commission to explore establishment of a fund and options for cost socialization with respect to catastrophic wildfires associated with utility infrastructure.

Since the passage of SB 901, each of Moody’s, Fitch Ratings and S&P downgraded SDG&E’s issuer rating and senior unsecured credit rating. If SDG&E were to be further downgraded or if Sempra Energy or SoCalGas or any other subsidiaries of Sempra Energy were to be downgraded, or if they were to receive any additional negative outlook on those credit ratings, it may adversely affect the market prices of Sempra Energy’s equity and debt securities and the debt securities of SDG&E and SoCalGas, the rates at which borrowings are made and, if applicable, commercial paper issued by Sempra Energy, SDG&E, SoCalGas or any of Sempra Energy’s other subsidiaries, and the various fees on their outstanding credit facilities. This could make it more costly for Sempra Energy, SDG&E, SoCalGas and Sempra Energy’s other subsidiaries to issue debt securities, to borrow under credit facilities and to raise certain other types of financing. Such amounts could materially and adversely affect our cash flows, results of operations and financial condition.

In their recent ratings actions for SDG&E, each of Moody’s, Fitch Ratings and S&P indicated that the downgrades reflected the failure of SB 901 to address the longer-term risks associated with inverse condemnation. In its September 6, 2018 report, Moody’s noted that SB 901 offers some constructive tools for the CPUC to utilize going forward in conducting its reasonableness review when considering whether to allow California utilities to recover catastrophic wildfire related costs, but that the reasonableness review will apply to wildfires that occur after January 1, 2019. This leaves a gap in coverage for any potential fires in 2018, which Moody’s indicated was a credit negative, particularly as the peak period of the wildfire season recently started. Moody’s also changed SDG&E’s rating outlook to stable from negative, and indicated that SDG&E’s credit rating would likely be downgraded if there is a deterioration in SDG&E’s credit metrics, such that its ratio of cash flow from operations before changes in working capital to debt falls to the low 20-percent range on a sustained basis or if there is a substantial increase in wildfire exposure. In a subsequent report issued on September 10, 2018, Moody’s also indicated that a downgrade to SDG&E’s ratings is likely if there are material changes to its shareholder rewards program, which appear overly biased to the benefit of equity at the expense of lenders, or if there is a substantial increase in regulatory contentiousness of new environmental risk exposures.

In its September 5, 2018 report, S&P indicated that SDG&E’s negative outlook reflects its view of the possibility of a lower rating if the severity of California’s wildfires persists without a longer-term reform to inverse condemnation, if SDG&E is deemed the cause of a significant wildfire that leads to material disallowances of wildfire costs, or if SDG&E’s stand-alone financial measures weaken such that its ratio of funds from operations to debt is consistently below 18 percent. S&P additionally noted that it could lower SDG&E’s credit rating within the next two years if the CPUC interprets SB 901 in a manner that does not limit the risks to the California electric utilities.

In its September 13, 2018 report downgrading SDG&E’s credit ratings and changing its ratings outlook to stable from negative, Fitch Ratings noted that although it views favorably SB 901’s establishment of the prudency review by the new commission referred to above to examine catastrophic wildfires associated with utility infrastructure, the method and timing of mechanisms to facilitate recovery of prudently incurred costs are yet to be established and implementation of SB 901 is subject to interpretation and political interference. Fitch Ratings also indicated that any further meaningful deterioration of the regulatory framework, accompanied by imminent and substantial financial loss at SDG&E, could negatively affect its credit ratings of Sempra Energy and SoCalGas. Furthermore, Fitch Ratings indicated that, if there is a materially unfavorable outcome in SDG&E’s 2019 GRC or its capital expenditure program is not prudently financed or experiences significant cost overruns or regulatory delay in cost

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recovery causing its funds from operations-adjusted leverage ratio to exceed 4.5x during construction, a negative rating action could occur and that SDG&E could be further downgraded if, following construction, its funds from operations-adjusted leverage ratio exceeds 4.0x on a sustained basis.

In its September 5, 2018 report reaffirming the investment grade ratings of Sempra Energy and SoCalGas, S&P indicated that its ratings affirmation followed the California legislature’s approval of SB 901 and further noted that the negative outlook for the credit ratings of Sempra Energy, SDG&E and SoCalGas reflects its view of, among other things, Sempra Energy’s modestly weakened business risk profile, that SB 901 is a shorter-term measure and that further longer-term reform is necessary in California to preserve electric utilities’ credit quality, including reforms to the inverse condemnation doctrine, as well as Sempra Energy’s relatively weak financial measures relative to its credit rating. S&P further indicated that it could lower ratings of Sempra Energy, SDG&E and SoCalGas within the next two years if the CPUC interprets SB 901 in a manner that does not limit risks to California electric utilities, and that it could lower Sempra Energy’s rating if SDG&E is the cause of a significant 2018 wildfire, if there is further weakening to SDG&E’s business risk profile reflecting persistent California wildfires without a longer-term reform to inverse condemnation, or if Sempra Energy’s financial measures do not improve so that its ratio of funds from operations before changes in working capital to debt is consistently above 16 percent beginning 2020.

In its September 26, 2018 report confirming Sempra Energy’s Baa1 issuer and senior unsecured ratings with outlook remaining negative, Moody’s indicated that the confirmation was predicated on a gradual improvement in Sempra Energy’s financial metrics, such that it generates cash flow from operations before changes in working capital to debt in excess of 16 percent by 2020. Some of the other considerations that Moody’s cited as reasons for confirming the ratings were management’s intention to deleverage Sempra Energy’s capital structure, the expectation that all three trains in the Cameron LNG project remain on schedule, the passage of SB 901 and the cooperation agreement executed on September 18, 2018 between Sempra Energy and affiliates of Elliott, Bluescape and Cove Key Management, LP. The ratings action concluded Moody’s review of Sempra Energy’s ratings initiated on June 25, 2018. Further, Moody’s indicated that the negative outlook reflects the challenges and execution risk that Sempra Energy still faces in meeting the targeted credit metrics and reducing leverage, as well as uncertainty around the outcome of the comprehensive business review of Sempra Energy’s LNG operations according to the cooperation agreement. Moody’s report indicated that a downgrade of Sempra Energy’s rating is likely if it fails to show a gradual improvement in its financial metrics as noted above, or does not address the upcoming holding company debt maturities beginning in January 2019. In addition, a downgrade of Sempra Energy’s rating is also possible if there are changes to its business risk or strategic direction that lead to a deterioration of Sempra Energy’s financial profile.

We discuss the 2007 wildfires and wildfire cost recovery further in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report and in Note 11 of the Notes to Condensed Consolidated Financial Statements herein, and we provide additional information about our credit ratings at Sempra Energy, SDG&E and SoCalGas in “Item 7. MD&A - Credit Ratings” in the Annual Report.

ITEM 6. EXHIBITS

The following exhibits relate to each registrant as indicated.

EXHIBIT 2 -- PLAN OF ACQUISITION, REORGANIZATION, ARRANGEMENT, LIQUIDATION OR SUCCESSION
Sempra Energy
2.1	Purchase and Sale Agreement, dated as of September 20, 2018, by and between Sempra Solar Portfolio Holdings, LLC and CED Southwest Holdings, Inc. (Form 8-K filed on September 20, 2018, Exhibit 2).
EXHIBIT 3 -- BYLAWS AND ARTICLES OF INCORPORATION
Sempra Energy
3.1	Certificate of Determination of the 6.75% Mandatory Convertible Preferred Stock, Series B, of Sempra Energy (including the form of certificate representing the 6.75% Mandatory Convertible Preferred Stock, Series B), filed with the Secretary of State of the State of California and effective July 11, 2018 (Form 8-K filed on July 13, 2018, Exhibit 3.1).

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EXHIBIT 4 -- INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS, INCLUDING INDENTURES
Sempra Energy
Sempra Energy agrees to furnish a copy of the following instrument to the Commission upon request:
4.1	Certificate of Determination of the 6.75% Mandatory Convertible Preferred Stock, Series B, of Sempra Energy (including the form of certificate representing the 6.75% Mandatory Convertible Preferred Stock, Series B), filed with the Secretary of State of the State of California and effective July 11, 2018 (Form 8-K filed on July 13, 2018, Exhibit 3.1).
EXHIBIT 10 -- MATERIAL CONTRACTS
Sempra Energy
10.1	Confirmation of Registered Forward Transaction, dated July 10, 2018, by and between Sempra Energy and Citibank, N.A. (Form 8-K filed on July 13, 2018, Exhibit 1.3).
10.2	Confirmation of Registered Forward Transaction, dated July 10, 2018, by and between Sempra Energy and JPMorgan Chase Bank, National Association, London Branch (Form 8-K filed on July 13, 2018, Exhibit 1.4).
10.3	Cooperation Agreement, dated as of September 18, 2018, by and between Elliott Associates, L.P., Elliott International, L.P., Bluescape Resources Company LLC, Cove Key Management, LP and Sempra Energy (Form 8-K filed on September 18, 2018, Exhibit 10.1).
San Diego Gas & Electric Company
Compensation
10.4	Severance Pay Agreement between Sempra Energy and Scott D. Drury dated August 25, 2018.
10.5	Severance Pay Agreement between Sempra Energy and Kevin C. Sagara dated September 8, 2018.
EXHIBIT 31 -- SECTION 302 CERTIFICATIONS
Sempra Energy
31.1	Certification of Sempra Energy’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.2	Certification of Sempra Energy’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
San Diego Gas & Electric Company
31.3	Certification of San Diego Gas & Electric Company’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.4	Certification of San Diego Gas & Electric Company’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
Southern California Gas Company
31.5	Certification of Southern California Gas Company’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.6	Certification of Southern California Gas Company’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

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EXHIBIT 32 -- SECTION 906 CERTIFICATIONS
Sempra Energy
32.1	Certification of Sempra Energy’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.2	Certification of Sempra Energy’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
San Diego Gas & Electric Company
32.3	Certification of San Diego Gas & Electric Company’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.4	Certification of San Diego Gas & Electric Company’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
Southern California Gas Company
32.5	Certification of Southern California Gas Company’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.6	Certification of Southern California Gas Company’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
EXHIBIT 101 -- INTERACTIVE DATA FILE
Sempra Energy/San Diego Gas & Electric Company/Southern California Gas Company
101.INS	XBRL Instance Document - the instance document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

Sempra Energy:
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
	SEMPRA ENERGY, (Registrant)
Date: November 7, 2018	By: /s/ Peter R. Wall
	Peter R. Wall Vice President, Controller and Chief Accounting Officer

San Diego Gas & Electric Company:
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
	SAN DIEGO GAS & ELECTRIC COMPANY, (Registrant)
Date: November 7, 2018	By: /s/ Bruce A. Folkmann
	Bruce A. Folkmann Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

Southern California Gas Company:
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
	SOUTHERN CALIFORNIA GAS COMPANY, (Registrant)
Date: November 7, 2018	By: /s/ Bruce A. Folkmann
	Bruce A. Folkmann Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

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