Edgar Filing: SEMPRA ENERGY

Document

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

March 31, 2018

[ ]

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from

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 and posted on their corporate websites, if any, every Interactive Data File required to be submitted and posted 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 and post such files).

	Yes	X	No

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 May 3, 2018:



Sempra Energy	264,137,837 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	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	91
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	124
Item 4.	Controls and Procedures	125

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	126
Item 1A.	Risk Factors	126
Item 6.	Exhibits	126

Signatures		128

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
ASU	Accounting Standards Update
Bankruptcy Court	U.S. Bankruptcy Court for the District of Delaware
Bay Gas	Bay Gas Storage Company, Ltd.
Bcf	billion cubic feet
bps	basis points
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)
Chilquinta Energía	Chilquinta Energía S.A. and its subsidiaries
CPCN	Certificate of Public Convenience and Necessity
CPI	Consumer Price Index
CPUC	California Public Utilities Commission
CRE	Comisión Reguladora de Energía (Energy Regulatory Commission in Mexico)
CRR	congestion revenue right
DA	Direct Access
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
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
EV	electric vehicle
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FTA	Free Trade Agreement
GCIM	Gas Cost Incentive Mechanism
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
IOU	investor-owned utility
IRC	U.S. Internal Revenue Code of 1986 (as amended)
IRS	Internal Revenue Service
ISFSI	independent spent fuel storage installation
ISO	Independent System Operator



GLOSSARY (CONTINUED)


JP Morgan	J.P. Morgan Chase & Co.
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)
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
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
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
SEC	U.S. Securities and Exchange Commission
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



GLOSSARY (CONTINUED)


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
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, 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, FERC, EPA, PHMSA, DPH, 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 and construction projects, including risks in obtaining or maintaining permits and other authorizations on a timely basis, risks in completing construction projects on schedule and on budget, and risks in obtaining the consent and participation of partners and counterparties;


▪	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 or modifications of settlements; and delays in, or disallowance or denial of, regulatory agency authorizations to recover costs in rates from customers (including with respect to amounts associated with the SONGS facility and 2007 wildfires) or regulatory agency approval for projects required to enhance safety and reliability, any of which may raise our cost of capital and materially impair our ability to finance our operations;


▪	the greater degree and prevalence of wildfires in California in recent years and risk that we may be found liable for damages regardless of fault, such as in cases where 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, natural gas and liquefied natural gas, and natural gas pipeline and storage capacity, including disruptions caused by failures in the transmission grid, moratoriums or limitations on the withdrawal or injection of natural gas from or into storage facilities, and equipment failures;


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


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

▪

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


▪	cybersecurity threats to the energy grid, storage and pipeline infrastructure, the information and systems used to operate our businesses and the confidentiality of our proprietary information and the personal information of our customers and employees;


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


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


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


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


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


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

▪

the impact on competitive customer rates due to the growth in distributed and local power generation and the corresponding decrease in demand for power delivered through SDG&E’s electric transmission and distribution system and from possible departing retail load resulting from customers transferring to DA and CCA or other forms of distributed and local power generation and the potential risk of nonrecovery for stranded assets and contractual obligations;


▪	the ability to realize the anticipated benefits from our investment in Oncor Holdings;


▪	the ability to obtain additional permanent equity financing for the acquisition of our investment in Oncor Holdings on favorable terms;


▪	indebtedness we have incurred to fund the acquisition of our investment in Oncor Holdings, which may make it more difficult for us to repay or refinance our debt or may require us to take other actions that may decrease business flexibility and increase borrowing costs;

▪

Oncor’s ability to eliminate or reduce its quarterly dividends due to its requirement to meet and maintain its regulatory capital structure, or because any of the three major credit rating agencies rates Oncor's senior secured debt securities below BBB (or the equivalent) or Oncor's independent directors or a minority member director determine it is in the best interest of Oncor to retain such amounts to meet future capital expenditures; 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 March 31,
	2018			2017⁽¹⁾
	(unaudited)
REVENUES
Utilities	$	2,598		$	2,698
Energy-related businesses	364			333
Total revenues	2,962			3,031

EXPENSES AND OTHER INCOME
Utilities:
Cost of electric fuel and purchased power	(546		)	(527		)
Cost of natural gas	(348		)	(485		)
Energy-related businesses:
Cost of natural gas, electric fuel and purchased power	(69		)	(67		)
Other cost of sales	(18		)	(22		)
Operation and maintenance	(781		)	(719		)
Depreciation and amortization	(386		)	(360		)
Franchise fees and other taxes	(117		)	(110		)
Other income, net	153			174
Interest income	33			6
Interest expense	(216		)	(169		)
Income before income taxes and equity losses of unconsolidated subsidiaries	667			752
Income tax expense	(289		)	(295		)
Equity losses	(20		)	(5		)
Net income	358			452
Losses (earnings) attributable to noncontrolling interests	17			(11		)
Mandatory convertible preferred stock dividends	(28		)	—
Earnings attributable to common shares	$	347		$	441


Basic earnings per common share	$	1.34		$	1.76
Weighted-average number of shares outstanding, basic (thousands)	257,932			251,131

Diluted earnings per common share	$	1.33		$	1.75
Weighted-average number of shares outstanding, diluted (thousands)	259,490			252,246

Dividends declared per share of common stock	$	0.90		$	0.82


⁽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			Net-of-tax amount			Noncontrolling interests (after-tax)			Total
	Three months ended March 31, 2018 and 2017
	(unaudited)
2018:
Net income (loss)	$	664		$	(289	)	$	375		$	(17	)	$	358
Other comprehensive income (loss):
Foreign currency translation adjustments	24			—			24			5			29
Financial instruments	88			(30		)	58			10			68
Pension and other postretirement benefits	3			(1		)	2			—			2
Total other comprehensive income	115			(31		)	84			15			99
Comprehensive income (loss)	779			(320		)	459			(2		)	457
Mandatory convertible preferred stock dividends	(28		)	—			(28		)	—			(28		)
Comprehensive income (loss), after
preferred dividends	$	751		$	(320	)	$	431		$	(2	)	$	429
2017:
Net income	$	736		$	(295	)	$	441		$	11		$	452
Other comprehensive income (loss):
Foreign currency translation adjustments	46			—			46			9			55
Financial instruments	7			(3		)	4			2			6
Pension and other postretirement benefits	3			(1		)	2			—			2
Total other comprehensive income	56			(4		)	52			11			63
Comprehensive income	$	792		$	(299	)	$	493		$	22		$	515

See Notes to Condensed Consolidated Financial Statements.



SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	March 31, 2018			December 31, 2017⁽¹⁾
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	239		$	288
Restricted cash	54			62
Accounts receivable – trade, net	1,328			1,307
Accounts receivable – other, net	353			277
Due from unconsolidated affiliates	63			37
Income taxes receivable	118			110
Inventories	285			307
Regulatory assets	241			325
Fixed-price contracts and other derivatives	111			66
Greenhouse gas allowances	301			299
Assets held for sale	135			127
Other	166			136
Total current assets	3,394			3,341

Other assets:
Restricted cash	14			14
Due from unconsolidated affiliates	666			598
Regulatory assets	1,597			1,517
Nuclear decommissioning trusts	1,017			1,033
Investment in Oncor Holdings	9,176			—
Other investments	2,590			2,527
Goodwill	2,406			2,397
Other intangible assets	596			596
Dedicated assets in support of certain benefit plans	421			455
Insurance receivable for Aliso Canyon costs	447			418
Deferred income taxes	117			170
Greenhouse gas allowances	154			93
Sundry	865			792
Total other assets	20,066			10,610

Property, plant and equipment:
Property, plant and equipment	48,857			48,108
Less accumulated depreciation and amortization	(11,832		)	(11,605		)
Property, plant and equipment, net ($316 and $321 at March 31, 2018 and December 31, 2017, respectively, related to VIE)	37,025			36,503
Total assets	$	60,485		$	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)
	March 31, 2018			December 31, 2017⁽¹⁾
	(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$	3,665		$	1,540
Accounts payable – trade	1,057			1,350
Accounts payable – other	148			173
Due to unconsolidated affiliates	6			7
Dividends and interest payable	494			342
Accrued compensation and benefits	253			439
Regulatory liabilities	210			109
Current portion of long-term debt	1,871			1,427
Fixed-price contracts and other derivatives	69			109
Customer deposits	164			162
Reserve for Aliso Canyon costs	122			84
Greenhouse gas obligations	301			299
Liabilities held for sale	52			49
Other	697			545
Total current liabilities	9,109			6,635

Long-term debt ($282 and $284 at March 31, 2018 and December 31, 2017, respectively, related to VIE)	20,863			16,445

Deferred credits and other liabilities:
Customer advances for construction	149			150
Due to unconsolidated affiliates	35			35
Pension and other postretirement benefit plan obligations, net of plan assets	1,215			1,148
Deferred income taxes	2,654			2,767
Deferred investment tax credits	26			28
Regulatory liabilities	3,922			3,922
Asset retirement obligations	2,766			2,732
Fixed-price contracts and other derivatives	275			316
Greenhouse gas obligations	19			—
Deferred credits and other	1,147			1,136
Total deferred credits and other liabilities	12,208			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)	1,693			—
Common stock (750 million shares authorized; 264 million and 251 million shares outstanding at March 31, 2018 and December 31, 2017, respectively; no par value)	4,436			3,149
Retained earnings	10,260			10,147
Accumulated other comprehensive income (loss)	(545		)	(626		)
Total Sempra Energy shareholders’ equity	15,844			12,670
Preferred stock of subsidiary	20			20
Other noncontrolling interests	2,441			2,450
Total equity	18,305			15,140
Total liabilities and equity	$	60,485		$	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)
	Three months ended March 31,
	2018			2017⁽¹⁾
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	358		$	452
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	386			360
Deferred income taxes and investment tax credits	229			268
Equity losses	20			5
Fixed-price contracts and other derivatives	(35		)	(106		)
Other	46			(22		)
Net change in other working capital components	84			84
Insurance receivable for Aliso Canyon costs	(29		)	(15		)
Changes in other assets	(107		)	(41		)
Changes in other liabilities	14			19
Net cash provided by operating activities	966			1,004

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(1,035		)	(992		)
Expenditures for investments and acquisitions, net of cash and cash equivalents acquired	(9,617		)	(59		)
Distributions from investments	8			17
Purchases of nuclear decommissioning trust assets	(210		)	(350		)
Proceeds from sales by nuclear decommissioning trusts	210			357
Advances to unconsolidated affiliates	(83		)	(5		)
Repayments of advances to unconsolidated affiliates	69			2
Other	26			4
Net cash used in investing activities	(10,632		)	(1,026		)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	(194		)	(176		)
Issuances of mandatory convertible preferred stock, net of $32 in offering costs	1,693			—
Issuances of common stock, net of $24 in offering costs	1,278			17
Repurchases of common stock	(19		)	(14		)
Issuances of debt (maturities greater than 90 days)	5,988			542
Payments on debt (maturities greater than 90 days)	(193		)	(313		)
Increase (decrease) in short-term debt, net	1,140			(97		)
Settlement of cross-currency swaps	(33		)	—
Other	(52		)	(5		)
Net cash provided by (used in) financing activities	9,608			(46		)

Effect of exchange rate changes on cash, cash equivalents and restricted cash	1			10

Decrease in cash, cash equivalents and restricted cash	(57		)	(58		)
Cash, cash equivalents and restricted cash, January 1	364			425
Cash, cash equivalents and restricted cash, March 31	$	307		$	367


⁽¹⁾	As adjusted for the retrospective adoption of 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)
	Three months ended March 31,
	2018			2017⁽¹⁾
	(unaudited)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	116		$	106
Income tax payments, net of refunds	34			47

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Acquisition:
Assets acquired	$	9,670		$	—
Liabilities assumed	(104		)	—
Cash paid	$	9,566		$	—

Accrued capital expenditures	$	340		$	378
Accrued Merger-related transaction and financing costs	6			—
Increase in capital lease obligations for investment in property, plant and equipment	5			—
Equitization of note receivable due from unconsolidated affiliate	—			19
Preferred dividends declared but not paid	28			—
Common dividends issued in stock	13			13
Common dividends declared but not paid	247			216


⁽¹⁾	As adjusted for the retrospective adoption of 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 OPERATIONS
(Dollars in millions)
	Three months ended March 31,
	2018			2017⁽¹⁾
	(unaudited)
Operating revenues
Electric	$	884		$	875
Natural gas	171			182
Total operating revenues	1,055			1,057
Operating expenses
Cost of electric fuel and purchased power	274			261
Cost of natural gas	50			65
Operation and maintenance	248			231
Depreciation and amortization	166			163
Franchise fees and other taxes	69			63
Total operating expenses	807			783
Operating income	248			274
Other income, net	28			22
Interest income	1			—
Interest expense	(52		)	(49		)
Income before income taxes	225			247
Income tax expense	(56		)	(90		)
Net income	169			157
Losses (earnings) attributable to noncontrolling interest	1			(2		)
Earnings attributable to common shares	$	170		$	155


⁽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			Net-of-tax amount		Noncontrolling interest (after-tax)			Total
	Three months ended March 31, 2018 and 2017
	(unaudited)
2018:
Net income (loss)	$	226	$	(56	)	$	170	$	(1	)	$	169
Other comprehensive income (loss):
Financial instruments	—		—			—		4			4
Total other comprehensive income	—		—			—		4			4
Comprehensive income	$	226	$	(56	)	$	170	$	3		$	173
2017:
Net income	$	245	$	(90	)	$	155	$	2		$	157
Other comprehensive income (loss):
Financial instruments	—		—			—		3			3
Total other comprehensive income	—		—			—		3			3
Comprehensive income	$	245	$	(90	)	$	155	$	5		$	160

See Notes to Condensed Consolidated Financial Statements.



SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	March 31, 2018			December 31, 2017⁽¹⁾
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	9		$	12
Restricted cash	5			6
Accounts receivable – trade, net	376			362
Accounts receivable – other, net	89			79
Inventories	106			105
Prepaid expenses	39			58
Regulatory assets	233			316
Fixed-price contracts and other derivatives	32			42
Greenhouse gas allowances	116			116
Other	25			4
Total current assets	1,030			1,100

Other assets:
Restricted cash	11			11
Regulatory assets	483			451
Nuclear decommissioning trusts	1,017			1,033
Greenhouse gas allowances	113			83
Sundry	301			328
Total other assets	1,925			1,906

Property, plant and equipment:
Property, plant and equipment	20,082			19,787
Less accumulated depreciation and amortization	(5,020		)	(4,949		)
Property, plant and equipment, net ($316 and $321 at March 31, 2018 and December 31, 2017, respectively, related to VIE)	15,062			14,838
Total assets	$	18,017		$	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)
	March 31, 2018			December 31, 2017⁽¹⁾
	(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$	340		$	253
Accounts payable	369			501
Due to unconsolidated affiliates	43			40
Interest payable	52			41
Accrued compensation and benefits	59			122
Accrued franchise fees	57			59
Current portion of long-term debt	220			220
Asset retirement obligations	87			77
Regulatory liabilities	8			18
Fixed-price contracts and other derivatives	57			60
Customer deposits	69			69
Greenhouse gas obligations	116			116
Other	139			46
Total current liabilities	1,616			1,622

Long-term debt ($282 and $284 at March 31, 2018 and December 31, 2017, respectively, related to VIE)	5,313			5,335

Deferred credits and other liabilities:
Customer advances for construction	54			57
Pension and other postretirement benefit plan obligations, net of plan assets	202			182
Deferred income taxes	1,496			1,530
Deferred investment tax credits	17			18
Regulatory liabilities	2,250			2,225
Asset retirement obligations	776			762
Fixed-price contracts and other derivatives	151			153
Greenhouse gas obligations	10			—
Deferred credits and other	334			334
Total deferred credits and other liabilities	5,290			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	4,438			4,268
Accumulated other comprehensive income (loss)	(8		)	(8		)
Total SDG&E shareholder’s equity	5,768			5,598
Noncontrolling interest	30			28
Total equity	5,798			5,626
Total liabilities and equity	$	18,017		$	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)
	Three months ended March 31,
	2018			2017⁽¹⁾
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	169		$	157
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	166			163
Deferred income taxes and investment tax credits	(11		)	34
Other	3			(12		)
Net change in other working capital components	102			84
Changes in other assets	(33		)	(34		)
Changes in other liabilities	8			(6		)
Net cash provided by operating activities	404			386

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(475		)	(418		)
Purchases of nuclear decommissioning trust assets	(210		)	(350		)
Proceeds from sales by nuclear decommissioning trusts	210			357
Decrease in loans to affiliate, net	—			31
Net cash used in investing activities	(475		)	(380		)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	—			(175		)
Payments on debt (maturities greater than 90 days)	(20		)	(160		)
Increase in short-term debt, net	87			343
Capital distributions made by VIE, net	—			(3		)
Net cash provided by financing activities	67			5

(Decrease) increase in cash, cash equivalents and restricted cash	(4		)	11
Cash, cash equivalents and restricted cash, January 1	29			20
Cash, cash equivalents and restricted cash, March 31	$	25		$	31

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	39		$	40

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY
Accrued capital expenditures	$	97		$	126


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

See Notes to Condensed Consolidated Financial Statements.



SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended March 31,
	2018			2017⁽¹⁾
	(unaudited)

Operating revenues	$	1,126		$	1,241
Operating expenses
Cost of natural gas	289			408
Operation and maintenance	384			356
Depreciation and amortization	135			126
Franchise fees and other taxes	40			39
Total operating expenses	848			929
Operating income	278			312
Other income, net	33			14
Interest expense	(27		)	(25		)
Income before income taxes	284			301
Income tax expense	(59		)	(98		)
Net Income/Earnings attributable to common shares	$	225		$	203


⁽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 expense			Net-of-tax amount
	Three months ended March 31, 2018 and 2017
	(unaudited)
2018:
Net income/Comprehensive income	$	284	$	(59	)	$	225
2017:
Net income/Comprehensive income	$	301	$	(98	)	$	203

See Notes to Condensed Financial Statements.



SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED BALANCE SHEETS
(Dollars in millions)
	March 31, 2018			December 31, 2017⁽¹⁾
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	11		$	8
Accounts receivable – trade, net	509			517
Accounts receivable – other, net	87			90
Due from unconsolidated affiliates	6			4
Income taxes receivable	—			10
Inventories	96			124
Regulatory assets	8			9
Greenhouse gas allowances	181			179
Other	38			38
Total current assets	936			979

Other assets:
Regulatory assets	1,031			983
Insurance receivable for Aliso Canyon costs	447			418
Greenhouse gas allowances	39			9
Sundry	363			364
Total other assets	1,880			1,774

Property, plant and equipment:
Property, plant and equipment	17,077			16,772
Less accumulated depreciation and amortization	(5,431		)	(5,366		)
Property, plant and equipment, net	11,646			11,406
Total assets	$	14,462		$	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)
	March 31, 2018			December 31, 2017⁽¹⁾
	(unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term debt	$	100		$	116
Accounts payable – trade	370			502
Accounts payable – other	89			93
Due to unconsolidated affiliates	37			35
Accrued compensation and benefits	99			151
Regulatory liabilities	202			91
Current portion of long-term debt	503			501
Customer deposits	91			89
Reserve for Aliso Canyon costs	122			84
Greenhouse gas obligations	181			179
Other	241			205
Total current liabilities	2,035			2,046

Long-term debt	2,486			2,485

Deferred credits and other liabilities:
Customer advances for construction	95			92
Pension obligation, net of plan assets	808			789
Deferred income taxes	1,085			995
Deferred investment tax credits	9			10
Regulatory liabilities	1,672			1,697
Asset retirement obligations	1,904			1,885
Greenhouse gas obligations	9			—
Deferred credits and other	227			253
Total deferred credits and other liabilities	5,809			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	3,265			3,040
Accumulated other comprehensive income (loss)	(21		)	(21		)
Total shareholders’ equity	4,132			3,907
Total liabilities and shareholders’ equity	$	14,462		$	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)
	Three months ended March 31,
	2018			2017
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	225		$	203
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	135			126
Deferred income taxes and investment tax credits	47			80
Other	21			(5		)
Net change in other working capital components	76			96
Insurance receivable for Aliso Canyon costs	(29		)	(15		)
Changes in other assets	(57		)	(21		)
Changes in other liabilities	1			(1		)
Net cash provided by operating activities	419			463

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(403		)	(357		)
Increase in loans to affiliate, net	—			(35		)
Other	3			—
Net cash used in investing activities	(400		)	(392		)

CASH FLOWS FROM FINANCING ACTIVITIES
Decrease in short-term debt, net	(16		)	(62		)
Net cash used in financing activities	(16		)	(62		)

Increase in cash and cash equivalents	3			9
Cash and cash equivalents, January 1	8			12
Cash and cash equivalents, March 31	$	11		$	21

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	18		$	16

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued capital expenditures	$	159		$	147
Increase in capital lease obligations for investment in property, plant and equipment	5			—

See Notes to Condensed Financial Statements.

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 Energy’s operating units are:


▪	Sempra Utilities, which includes our SDG&E, SoCalGas, Sempra South American Utilities and our newly formed Sempra Texas Utility reportable segments. We discuss our new Sempra Texas Utility reportable segment in Notes 5 and 6; and


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

We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include our Texas utility investment, South American utilities or the utility in our Sempra Infrastructure operating unit. Sempra Global is the holding company for most of our subsidiaries that are not subject to California or Texas utility regulation. All references in these Notes to “Sempra Utilities,” “Sempra Infrastructure” and their respective 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.

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 March 31, 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 ended March 31, 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 this presentation 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 March 31, 2017
		As previously presented			As currently presented
Condensed Consolidated Statement of Operations:
Equity earnings, before income tax		$	3		$	—
Income before income taxes and equity losses of certain
unconsolidated subsidiaries		755			—
Income before income taxes and equity losses of
unconsolidated subsidiaries		—			752
Equity losses, net of income tax		(8		)	—
Equity losses		—			(5		)

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.

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.

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.

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)
	March 31,
	2018
Sempra Energy Consolidated:
Cash and cash equivalents	$	239
Restricted cash, current	54
Restricted cash, noncurrent	14
Total cash, cash equivalents and restricted cash on the Condensed Consolidated Statement of Cash Flows	$	307
SDG&E:
Cash and cash equivalents	$	9
Restricted cash, current	5
Restricted cash, noncurrent	11
Total cash, cash equivalents and restricted cash on the Condensed Consolidated Statement of Cash Flows	$	25

INVENTORIES

The components of inventories by segment are as follows:



INVENTORY BALANCES
(Dollars in millions)
	Natural gas				LNG				Materials and supplies				Total
	March 31, 2018		December 31, 2017		March 31, 2018		December 31, 2017		March 31, 2018		December 31, 2017		March 31, 2018		December 31, 2017
SDG&E	$	2	$	4	$	—	$	—	$	104	$	101	$	106	$	105
SoCalGas	55		75		—		—		41		49		96		124
Sempra South American Utilities	—		—		—		—		32		30		32		30
Sempra Mexico	1		—		7		7		3		2		11		9
Sempra Renewables	—		—		—		—		5		5		5		5
Sempra LNG & Midstream	35		30		—		4		—		—		35		34
Sempra Energy Consolidated	$	93	$	109	$	7	$	11	$	185	$	187	$	285	$	307

GOODWILL

We discuss goodwill in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. The increase in goodwill from $2,397 million at December 31, 2017 to $2,406 million at March 31, 2018 is due to foreign currency translation at Sempra South American Utilities. We record the offset of this fluctuation in OCI.

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.

Interest capitalized and AFUDC are as follows:



CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Three months ended March 31,
	2018		2017
Sempra Energy Consolidated	$	51	$	82
SDG&E	24		20
SoCalGas	13		15

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 provides SDG&E with the option to purchase OMEC at the end of the contract term in October 2019, or upon earlier termination of the PPA, at a predetermined price subject to adjustments. If SDG&E does not exercise its option (referred to as the call option), 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 $30 million at March 31, 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.

OMEC LLC has a loan outstanding of $292 million at March 31, 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 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 March 31,
	2018			2017
Operating expenses
Cost of electric fuel and purchased power	$	(16	)	$	(18	)
Operation and maintenance	4			4
Depreciation and amortization	8			7
Total operating expenses	(4		)	(7		)
Operating income	4			7
Interest expense	(5		)	(5		)
(Losses) income before income taxes/Net (loss) income	(1		)	2
Losses (earnings) attributable to noncontrolling interest	1			(2		)
Earnings attributable to common shares	$	—		$	—

SDG&E has determined that no contracts, other than the one relating to Otay Mesa VIE mentioned above, result in SDG&E being the primary beneficiary of a VIE at March 31, 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 does not exceed the carrying value of our investment, which is $9,176 million at March 31, 2018. Our maximum exposure will fluctuate over time.

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 both March 31, 2018 and December 31, 2017 and equity of $607 million and $631 million included in Other Noncontrolling Interests at March 31, 2018 and December 31, 2017, respectively, associated with these entities. Sempra Energy’s Condensed Consolidated Statements of Operations for the three months ended March 31, 2018 and 2017 include the following amounts associated with the tax equity limited liability companies. The amounts are net of eliminations of transactions between Sempra Energy and these entities.



AMOUNTS ASSOCIATED WITH TAX EQUITY ARRANGEMENTS
(Dollars in millions)
	Three months ended March 31,
	2018			2017
REVENUES
Energy-related businesses	$	17		$	13
EXPENSES
Operation and maintenance	(4		)	(2		)
Depreciation and amortization	(11		)	(8		)
Income before income taxes	2			3
Income tax expense	(5		)	(2		)
Net (loss) income	(3		)	1
Losses attributable to noncontrolling interests⁽¹⁾	21			3
Earnings	$	18		$	4


⁽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 $1,085 million at March 31, 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 contracts are not variable interests in a VIE and therefore are not subject to the U.S. GAAP requirements concerning the consolidation of VIEs.

PENSION AND OTHER POSTRETIREMENT BENEFITS

Sale of Qualified Pension Plan Annuity Contracts

In March 2018, an insurance company purchased certain annuities for current annuitants in the SDG&E and SoCalGas qualified pension plans and assumed the obligation for payment of these annuities. At SDG&E, 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 $83 million at Sempra Energy Consolidated and SDG&E. This also resulted in a settlement charge in net periodic benefit cost of $14 million at Sempra Energy Consolidated and SDG&E in the first quarter of 2018. This settlement charge at SDG&E was recorded as a regulatory asset on the Condensed Consolidated Balance Sheets. The measurement date of March 31, 2018 was used for the settlement accounting, as the liability for the annuities transferred, plus the year-to-date lump sum benefit payments, first exceeded the settlement threshold in March 2018.

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 March 31,
	2018			2017			2018			2017
Service cost	$	33		$	28		$	6		$	6
Interest cost	35			37			9			9
Expected return on assets	(42		)	(40		)	(18		)	(16		)
Amortization of:
Prior service cost	3			3			—			—
Actuarial loss (gain)	9			8			(1		)	(1		)
Settlements	14			—			—			—
Net periodic benefit cost (credit)	52			36			(4		)	(2		)
Regulatory adjustment	(45		)	(12		)	4			2
Total expense recognized	$	7		$	24		$	—		$	—



NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	Three months ended March 31,
	2018			2017			2018			2017
Service cost	$	8		$	8		$	1		$	1
Interest cost	9			9			2			2
Expected return on assets	(13		)	(11		)	(3		)	(3		)
Amortization of:
Prior service cost	—			—			1			1
Actuarial loss (gain)	1			2			(1		)	—
Settlements	14			—			—			—
Net periodic benefit cost	19			8			—			1
Regulatory adjustment	(19		)	(7		)	—			(1		)
Total expense recognized	$	—		$	1		$	—		$	—



NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	Three months ended March 31,
	2018			2017			2018			2017
Service cost	$	22		$	18		$	4		$	4
Interest cost	23			24			7			7
Expected return on assets	(26		)	(26		)	(14		)	(13		)
Amortization of:
Prior service cost (credit)	2			2			(1		)	(1		)
Actuarial loss	6			4			—			—
Net periodic benefit cost (credit)	27			22			(4		)	(3		)
Regulatory adjustment	(26		)	(5		)	4			3
Total expense recognized	$	1		$	17		$	—		$	—

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 March 31, 2018:
Pension plans	$	10	$	2	$	—
Other postretirement benefit plans	1		—		1
Total expected contributions in 2018:
Pension plans	$	226	$	48	$	113
Other postretirement benefit plans	9		3		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 $421 million and $455 million at March 31, 2018 and December 31, 2017, respectively.

EARNINGS PER COMMON SHARE

The following table provides EPS computations for the three months ended March 31, 2018 and 2017. Basic EPS is calculated by dividing earnings attributable to common stock 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 March 31,
	2018		2017
Numerator:
Earnings/Income attributable to common shares	$	347	$	441

Denominator:
Weighted-average common shares outstanding for basic EPS⁽¹⁾	257,932		251,131
Dilutive effect of stock options, RSAs and RSUs⁽²⁾	933		1,115
Dilutive effect of common stock shares sold forward	625		—
Weighted-average common shares outstanding for diluted EPS	259,490		252,246

EPS:
Basic	$	1.34	$	1.76
Diluted	$	1.33	$	1.75


⁽¹⁾	Includes 628 and 600 average fully vested RSUs held in our Deferred Compensation Plan for the three months ended March 31, 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 March 31, 2018 and 2017 excludes 80,449 and 6,801 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.

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 Offering,” is reflected in our diluted EPS calculation using the treasury stock method. We anticipate there will be a dilutive effect on our EPS except during periods when the average market price of shares of our common stock is below 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. 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 our 6% mandatory convertible preferred stock, series A (mandatory convertible preferred stock) issued in January 2018 is calculated under the if-converted method. The computation of diluted EPS for the three months ended March 31, 2018 excludes 15,592,572 potentially dilutive shares, because to include them would be antidilutive for the period. However, these shares could potentially dilute basic EPS in the future. We discuss the issuance of the mandatory

convertible preferred stock in “Shareholders’ Equity and Noncontrolling Interests – Sempra Energy 6% Mandatory Convertible Preferred Stock, Series A” below.

Pursuant to our Sempra Energy share-based compensation plans, Sempra Energy’s Board of Directors granted 356,496 performance-based RSUs and 195,994 service-based RSUs during the three months ended March 31, 2018, primarily in January. During the three months ended March 31, 2018, IEnova granted 437,729 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 March 31, 2018 and 2017
Sempra Energy Consolidated:
Balance as of December 31, 2017	$	(420	)	$	(122	)	$	(84	)	$	(626	)
Cumulative-effect adjustment from change in accounting principle	—			(3		)	—			(3		)
OCI before reclassifications	24			66			—			90
Amounts reclassified from AOCI	—			(8		)	2			(6		)
Net OCI	24			58			2			84
Balance as of March 31, 2018	$	(396	)	$	(67	)	$	(82	)	$	(545	)
							.
Balance as of December 31, 2016	$	(527	)	$	(125	)	$	(96	)	$	(748	)
OCI before reclassifications	46			(2		)	—			44
Amounts reclassified from AOCI	—			6			2			8
Net OCI	46			4			2			52
Balance as of March 31, 2017	$	(481	)	$	(121	)	$	(94	)	$	(696	)
SDG&E:
Balance as of December 31, 2017 and March 31, 2018							$	(8	)	$	(8	)

Balance as of December 31, 2016 and March 31, 2017							$	(8	)	$	(8	)
SoCalGas:
Balance as of December 31, 2017 and March 31, 2018				$	(13	)	$	(8	)	$	(21	)

Balance as of December 31, 2016 and March 31, 2017				$	(13	)	$	(9	)	$	(22	)


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



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 March 31,
	2018			2017
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments⁽¹⁾	$	(2	)	$	(3	)	Interest Expense
	(18		)	—			Other Income, Net
Interest rate and foreign exchange instruments	4			4			Equity Losses
Foreign exchange instruments	—			2			Revenues: Energy-Related Businesses
Commodity contracts not subject to rate recovery	—			9			Revenues: Energy-Related Businesses
Total before income tax	(16		)	12
	3			(4		)	Income Tax Expense
Net of income tax	(13		)	8
	5			(2		)	Losses (Earnings) Attributable to Noncontrolling Interests
	$	(8	)	$	6
Pension and other postretirement benefits:
Amortization of actuarial loss⁽²⁾	$	3		$	3		Other Income, Net
	(1		)	(1		)	Income Tax Expense
Net of income tax	$	2		$	2

Total reclassifications for the period, net of tax	$	(6	)	$	8
SDG&E:
Financial instruments:
Interest rate instruments⁽¹⁾	$	3		$	3		Interest Expense
	(3		)	(3		)	Losses (Earnings) Attributable to Noncontrolling Interest
Total reclassifications for the period, net of tax	$	—		$	—


⁽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).

For the three months ended March 31, 2018 and 2017, reclassifications out of AOCI to net income were negligible for SoCalGas.

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS

The following tables provide reconciliations of changes in Sempra Energy’s, SDG&E’s and SoCalGas’ shareholders’ equity and NCI for the three months ended March 31, 2018 and 2017.



SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Sempra Energy shareholders’ equity			Non- controlling interests⁽¹⁾			Total equity
Balance at December 31, 2017	$	12,670		$	2,470		$	15,140
Cumulative-effect adjustment from change in accounting principle	(1		)	—			(1		)
Comprehensive income (loss)	459			(2		)	457
Share-based compensation expense	15			—			15
Mandatory convertible preferred stock dividends declared	(28		)	—			(28		)
Common stock dividends declared	(236		)	—			(236		)
Issuances of mandatory convertible preferred stock	1,693			—			1,693
Issuances of common stock	1,291			—			1,291
Repurchases of common stock	(19		)	—			(19		)
Distributions to noncontrolling interests	—			(7		)	(7		)
Balance at March 31, 2018	$	15,844		$	2,461		$	18,305
Balance at December 31, 2016	$	12,951		$	2,290		$	15,241
Comprehensive income	493			22			515
Share-based compensation expense	10			—			10
Common stock dividends declared	(206		)	—			(206		)
Issuances of common stock	30			—			30
Repurchases of common stock	(14		)	—			(14		)
Distributions to noncontrolling interests	—			(7		)	(7		)
Balance at March 31, 2017	$	13,264		$	2,305		$	15,569


⁽¹⁾	NCI includes the preferred stock of SoCalGas and other NCI as listed in the table below under “Other Noncontrolling Interests.”



SHAREHOLDER’S EQUITY AND NONCONTROLLING INTEREST – SDG&E
(Dollars in millions)
	SDG&E shareholder’s equity			Non- controlling interest			Total equity
Balance at December 31, 2017	$	5,598		$	28		$	5,626
Comprehensive income	170			3			173
Distributions to noncontrolling interest	—			(1		)	(1		)
Balance at March 31, 2018	$	5,768		$	30		$	5,798
Balance at December 31, 2016	$	5,641		$	37		$	5,678
Comprehensive income	155			5			160
Common stock dividends declared	(175		)	—			(175		)
Distributions to noncontrolling interest	—			(3		)	(3		)
Balance at March 31, 2017	$	5,621		$	39		$	5,660



SHAREHOLDERS’ EQUITY – SOCALGAS
(Dollars in millions)
	Total equity
Balance at December 31, 2017	$	3,907
Comprehensive income	225
Balance at March 31, 2018	$	4,132
Balance at December 31, 2016	$	3,510
Comprehensive income	203
Balance at March 31, 2017	$	3,713

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 comprehensive income or loss attributable to NCI is separately identified on the Condensed Consolidated Statements of Comprehensive Income (Loss).

Sempra Energy 6% Mandatory Convertible Preferred Stock, Series A

On January 9, 2018, we sold 17,250,000 shares of our mandatory convertible preferred stock at $100.00 per share (or $98.20 per share after deducting the underwriting discount), 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 mandatory convertible 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. We discuss the terms of the mandatory convertible preferred stock in Note 18 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra Energy Common Stock Offering

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 ($105.074 per share after deducting the underwriting discount), 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. The initial forward sale price under the forward sale agreements is $105.074 per share, which was the public offering price in the common stock offering less the underwriting discount. However, the forward sale price is subject to adjustment pursuant to the forward sale agreements. We did not initially receive any proceeds from the sale of our common stock sold by the forward sellers to the underwriters.

On March 8, 2018, we settled approximately $900 million (net of underwriting discounts of $16 million) of forward sales under the forward sale agreements by delivering 8,556,630 shares of newly issued Sempra Energy common stock at a forward sale price of $105.1816 per share.

As of May 7, 2018, a total of 14,807,856 shares of Sempra Energy common stock remain subject to future settlement under the forward sale agreements, which may be settled on one or more dates specified by us occurring no later than December 15, 2019. 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.

We used the net proceeds from the sale of shares in the January 2018 offering and from the settlement of forward sales in March 2018 under the forward sale agreements to fund a portion of the Merger Consideration, as we discuss in Note 5.

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

At March 31, 2018 and December 31, 2017, we reported the following 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 held by noncontrolling interests
	March 31, 2018		December 31, 2017		March 31, 2018		December 31, 2017
SDG&E:
Otay Mesa VIE	100	%	100	%	$	30	$	28
Sempra South American Utilities:
Chilquinta Energía subsidiaries⁽¹⁾	22.9 – 43.4		22.9 – 43.4		26		24
Luz del Sur	16.4		16.4		193		189
Tecsur	9.8		9.8		4		4
Sempra Mexico:
IEnova⁽²⁾	33.6		33.6		1,539		1,532
Sempra Renewables:
Tax equity arrangements – wind⁽³⁾	NA		NA		167		181
Tax equity arrangements – solar⁽³⁾	NA		NA		440		450
Sempra LNG & Midstream:
Bay Gas	9.1		9.1		29		28
Liberty Gas Storage, LLC	23.4		23.3		13		14
Total Sempra Energy					$	2,441	$	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 March 31, 2018 and December 31, 2017.


⁽³⁾	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 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

Amounts due from and to unconsolidated affiliates at Sempra Energy Consolidated, SDG&E and SoCalGas are as follows:



AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	March 31, 2018			December 31, 2017
Sempra Energy Consolidated:
Total due from various unconsolidated affiliates – current	$	63		$	37

Sempra South American Utilities⁽¹⁾:
Eletrans – 4% Note⁽²⁾	$	38		$	103
Other related party receivables	1			1
Sempra Mexico⁽¹⁾:
IMG – Note due March 15, 2022⁽³⁾	621			487
Energía Sierra Juárez – Note⁽⁴⁾	6			7
Total due from unconsolidated affiliates – noncurrent	$	666		$	598

Total due to various unconsolidated affiliates – current	$	(6	)	$	(7	)

Sempra Mexico⁽¹⁾:
Total due to unconsolidated affiliates – noncurrent – TAG – Note due December 20, 2021⁽⁵⁾	$	(35	)	$	(35	)
SDG&E:
Sempra Energy	$	(32	)	$	(30	)
SoCalGas	(5		)	(4		)
Various affiliates	(6		)	(6		)
Total due to unconsolidated affiliates – current	$	(43	)	$	(40	)

Income taxes due (to) from Sempra Energy⁽⁶⁾	$	(39	)	$	27
SoCalGas:
SDG&E	$	5		$	4
Various affiliates	1			—
Total due from unconsolidated affiliates – current	$	6		$	4

Total due to unconsolidated affiliates – current – Sempra Energy	$	(37	)	$	(35	)

Income taxes due (to) from Sempra Energy⁽⁶⁾	$	(2	)	$	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 $777 million U.S. dollar-equivalent, at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus 220 bps (10.07 percent at March 31, 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 (8.26 percent at March 31, 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 (5.35 percent at March 31, 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.

Revenues and cost of sales from unconsolidated affiliates are as follows:



REVENUES AND COST OF SALES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
	Three months ended March 31,
	2018		2017
Revenues:
Sempra Energy Consolidated	$	16	$	7
SDG&E	2		2
SoCalGas	17		18
Cost of Sales:
Sempra Energy Consolidated	$	12	$	14
SDG&E	19		20

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 has 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 consists of the following:



OTHER INCOME, NET
(Dollars in millions)
	Three months ended March 31,
	2018			2017⁽¹⁾
Sempra Energy Consolidated:
Allowance for equity funds used during construction	$	27		$	72
Investment (losses) gains⁽²⁾	(1		)	16
Gains on interest rate and foreign exchange instruments, net	62			63
Foreign currency transaction gains, net⁽³⁾	30			10
Non-service component of net periodic benefit credit	32			5
Interest on regulatory balancing accounts, net	—			2
Sundry, net	3			6
Total	$	153		$	174
SDG&E:
Allowance for equity funds used during construction	$	18		$	15
Non-service component of net periodic benefit credit	9			4
Interest on regulatory balancing accounts, net	—			2
Sundry, net	1			1
Total	$	28		$	22
SoCalGas:
Allowance for equity funds used during construction	$	9		$	11
Non-service component of net periodic benefit credit	25			3
Sundry, net	(1		)	—
Total	$	33		$	14


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


⁽²⁾	Represents investment (losses) gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans, recorded in Operation and Maintenance on the Condensed Consolidated Statements of Operations.


⁽³⁾	Includes $39 million gain in 2018 from translation to U.S. dollars of a Mexican peso-denominated loan to the IMG joint venture, which is offset by a $39 million loss in Equity Losses on the Condensed Consolidated Statement of Operations.

INCOME TAXES



INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Pretax income		Income tax expense		ETR		Pretax income		Income tax expense		ETR
	Three months ended March 31,
	2018						2017
Sempra Energy Consolidated⁽¹⁾	$	672	$	289	43	%	$	755	$	295	39	%
SDG&E	225		56		25		247		90		36
SoCalGas	284		59		21		301		98		33


⁽¹⁾	Sempra Energy's pretax income represents Income Before Income Taxes and Equity Losses of Unconsolidated Subsidiaries plus equity earnings before income tax of $5 million and $3 million in the three months ended March 31, 2018 and 2017, respectively. 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 actually 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.

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, 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 rulings by the U.S. Department of the Treasury or states, the filing of our 2017 income tax return and the finalization of our calculation of foreign undistributed earnings. In the three months ended March 31, 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. SDG&E decreased its deferred tax liabilities by $38 million and SoCalGas increased its deferred tax liabilities by $5 million, with each amount offset by a change in their respective regulatory liabilities.

In the three months ended March 31, 2018 and 2017, we recorded $94 million ($63 million after NCI) and $97 million ($65 million after NCI), respectively, of income tax expense primarily from the transactional effects of Mexican foreign currency and inflation. In the three months ended March 31, 2018 and 2017, we recorded net gains of $44 million ($32 million after-tax) and $65 million ($39 million after-tax), respectively, in Other Income, Net, on the Condensed Consolidated Statements of Operations, from foreign currency derivatives that are hedging Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova.

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 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” and ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842”: 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 maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous 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 2018-01 allows entities to elect a transition 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.

For public entities, these ASUs are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. 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. The modified retrospective approach includes practical expedients that may be elected, which would allow entities to continue to account for leases that commence before the effective date of the standard in accordance with previous U.S. GAAP unless the lease is modified, except for the lessee requirement to begin recognizing right-of-use assets and lease liabilities for all operating leases on the balance sheet

at the reporting date. We are currently evaluating the effect of the standards on our ongoing financial reporting and plan to adopt the standards on January 1, 2019. As part of our evaluation, we formed a steering committee comprised of members from relevant Sempra Energy business units, are compiling 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 practical expedients available under the transition guidance described above. The FASB recently approved amendments to create an additional transition method to apply ASU 2016-02 in the period of adoption rather than in the earliest period presented and a lessor practical expedient for separating lease and non-lease components. The FASB is in the process of finalizing a new ASU that would amend ASU 2016-02.

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, with early adoption permitted for fiscal years beginning after December 15, 2018. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in which we will adopt the standard.

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. The adoption of ASU 2016-15 did not impact the Sempra Energy or SDG&E Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2017, based on the timing of cash receipts and cash payments affected by the ASU.

Upon adoption of ASU 2016-18, Sempra Energy’s and SDG&E’s Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2017 were impacted as follows:



IMPACT FROM ADOPTION OF ASU 2016-18
(Dollars in millions)
	Three months ended March 31, 2017
	As previously reported			Effect of adoption			As adjusted
Sempra Energy Condensed Consolidated Statement of Cash Flows:
Cash flows from investing activities:
Increases in restricted cash	$	(93	)	$	93		$	—
Decreases in restricted cash	93			(93		)	—

Effect of exchange rate changes on cash and cash equivalents	9			(9		)	—
Effect of exchange rate changes on cash, cash equivalents and restricted cash	—			10			10

Decrease in cash and cash equivalents	(59		)	59			—
Decrease in cash, cash equivalents, and restricted cash	—			(58		)	(58		)

Cash and cash equivalents, January 1	349			(349		)	—
Cash, cash equivalents and restricted cash, January 1	—			425			425
Cash and cash equivalents, March 31	290			(290		)	—
Cash, cash equivalents and restricted cash, March 31	—			367			367
SDG&E Condensed Consolidated Statement of Cash Flows:
Cash flows from investing activities:
Increases in restricted cash	$	(10	)	$	10		$	—
Decreases in restricted cash	9			(9		)	—
Net cash used in investing activities	(381		)	1			(380		)

Increase in cash and cash equivalents	10			(10		)	—
Increase in cash, cash equivalents, and restricted cash	—			11			11

Cash and cash equivalents, January 1	8			(8		)	—
Cash, cash equivalents and restricted cash, January 1	—			20			20
Cash and cash equivalents, March 31	18			(18		)	—
Cash, cash equivalents and restricted cash, March 31	—			31			31

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 for the three months ended March 31, 2017 were impacted as follows:



IMPACT FROM ADOPTION OF ASU 2017-07
(Dollars in millions)
	Three months ended March 31, 2017
	As previously reported		Effect of adoption			As adjusted
Sempra Energy Condensed Consolidated Statement of Operations:
Operation and maintenance	$	714	$	5		$	719
Other income, net	169		5			174
SDG&E Condensed Consolidated Statement of Operations:
Operation and maintenance	$	227	$	4		$	231
Total operating expenses	779		4			783
Operating income	278		(4		)	274
Other income, net	18		4			22
SoCalGas Condensed Statement of Operations:
Operation and maintenance	$	353	$	3		$	356
Total operating expenses	926		3			929
Operating income	315		(3		)	312
Other income, net	11		3			14

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 are currently evaluating the effect of the standard on our financial reporting and have not yet selected the adoption method or the year in which we will adopt the standard.

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 (SAB) No. 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 No. 118, and is effective upon issuance. We are applying SAB No. 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.

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 for the three months ended March 31, 2018.



DISAGGREGATED REVENUES
(Dollars in millions)
	Three months ended March 31, 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	$	1,131		$	1,081	$	408	$	28	$	—	$	—	$	(19	)	$	2,629
Midstream	—			—		—		143		—		54		(21		)	176
Renewables	—			—		—		22		11		1		(1		)	33
Other	—			—		17		41		—		2		(2		)	58
Revenues from contracts with customers	$	1,131		$	1,081	$	425	$	234	$	11	$	57	$	(43	)	$	2,896

By market:
Electric	$	963		$	—	$	425	$	62	$	11	$	2	$	(4	)	$	1,459
Gas	168			1,081		—		172		—		55		(39		)	1,437
Revenues from contracts with customers	$	1,131		$	1,081	$	425	$	234	$	11	$	57	$	(43	)	$	2,896

By timing of recognition:
Over time	$	1,104		$	1,051	$	420	$	234	$	11	$	40	$	(37	)	$	2,823
Point in time	27			30		5		—		—		17		(6		)	73
Revenues from contracts with customers	$	1,131		$	1,081	$	425	$	234	$	11	$	57	$	(43	)	$	2,896

Revenues from contracts with customers	$	1,131		$	1,081	$	425	$	234	$	11	$	57	$	(43	)	$	2,896
Utilities regulatory revenues	(76		)	45		—		—		—		—		—			(31		)
Other revenues	—			—		1		74		14		47		(39		)	97
Total revenues	$	1,055		$	1,126	$	426	$	308	$	25	$	104	$	(82	)	$	2,962

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.

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 CPI, 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.

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. TdM is currently held for sale, as we discuss in Note 5.

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 March 31, 2018, we expect 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 March 31, 2018.



REMAINING PERFORMANCE OBLIGATIONS⁽¹⁾
(Dollars in millions)
	Sempra Energy Consolidated		SDG&E
2018	$	531	$	2
2019	533		3
2020	532		3
2021	528		3
2022	531		3
Thereafter	3,384		55
Total revenues to be recognized	$	6,039	$	69


⁽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 for the three months ended March 31, 2018 are presented below. There were no contract liabilities at SDG&E or SoCalGas at March 31, 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	12
Payments received in advance	(15		)
Closing balance, March 31, 2018⁽¹⁾	$	(71	)


⁽¹⁾	Includes $9 million in Other Current Liabilities and $62 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)
	March 31, 2018		January 1, 2018
Sempra Energy Consolidated:
Accounts receivable – trade, net	$	1,226	$	1,194
Accounts receivable – other, net	11		10
Due from unconsolidated affiliates – current	9		8
Total	$	1,246	$	1,212
SDG&E:
Accounts receivable – trade, net	$	376	$	362
Accounts receivable – other, net	6		3
Due from unconsolidated affiliates – current⁽¹⁾	3		3
Total	$	385	$	368
SoCalGas:
Accounts receivable – trade, net	$	509	$	517
Accounts receivable – other, net	3		7
Total	$	512	$	524


⁽¹⁾	This amount is netted against current amounts due to unconsolidated affiliates on the SDG&E Condensed Consolidated Balance Sheet.

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 incorporation in 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 IOUs, under which the California Utilities have earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals. Generally, for performance-based awards, if performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties.

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, 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 with 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 supplier 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 revenue 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)
	March 31, 2018			December 31, 2017

SDG&E:
Fixed-price contracts and other derivatives	$	103		$	96
Deferred income taxes refundable in rates	(305		)	(281		)
Pension and other postretirement benefit plan obligations	170			153
Removal obligations	(1,827		)	(1,846		)
Unamortized loss on reacquired debt	8			9
Environmental costs	29			29
Sunrise Powerlink fire mitigation	120			119
Regulatory balancing accounts⁽¹⁾
Commodity – electric	112			82
Gas transportation	19			22
Safety and reliability	52			48
Public purpose programs	(83		)	(70		)
Other balancing accounts	149			233
Other regulatory liabilities	(89		)	(70		)
Total SDG&E	(1,542		)	(1,476		)
SoCalGas:
Pension and other postretirement benefit plan obligations	529			513
Employee benefit costs	45			45
Removal obligations	(910		)	(924		)
Deferred income taxes refundable in rates	(395		)	(437		)
Unamortized loss on reacquired debt	7			8
Environmental costs	21			22
Workers’ compensation	12			12
Regulatory balancing accounts⁽¹⁾
Commodity – gas, including transportation	168			151
Safety and reliability	275			266
Public purpose programs	(353		)	(274		)
Other balancing accounts	(149		)	(114		)
Other regulatory liabilities	(85		)	(64		)
Total SoCalGas	(835		)	(796		)
Sempra Mexico:
Deferred income taxes recoverable in rates	83			83
Total Sempra Energy Consolidated	$	(2,294	)	$	(2,189	)


⁽¹⁾	At March 31, 2018 and December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $72 million and $63 million, respectively. At March 31, 2018 and December 31, 2017, the noncurrent portion of regulatory balancing accounts – net undercollected for SoCalGas was $141 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 requested revenue requirements for 2019 of $2.199 billion and $2.989 billion, respectively, which is an increase of $217 million and $533 million over their respective 2018 revenue requirements (the 2018 revenue requirements reflect the impact of updated testimony filed in January 2018). The California Utilities are proposing post-test year revenue requirement changes using various adjustment factors which 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. Our 2019 GRC applications do 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 to $2.931 billion.

In April 2018, ORA filed testimony in SDG&E’s and SoCalGas’ 2019 GRC recommending a 2019 revenue requirement of $1.918 billion and $2.695 billion, respectively, which is a net decrease of $64 million and an increase of $239 million compared to the respective 2018 revenue requirements. ORA’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. ORA recommends addressing SDG&E’s potential ownership of OMEC in a separate proceeding. As a result, ORA’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.

As part of the 2019 GRC, the CPUC will review 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. The stated purpose of the interim accountability reports is to provide data and metrics for key safety and risk mitigation areas that will be considered in the 2019 GRC.

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

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 recommending more detailed analysis of the risks the California Utilities 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, requiring 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. This requirement is effective beginning January 1, 2018. The form of this reporting is not yet defined by the CPUC, though it could be incorporated into an ongoing proceeding or report otherwise required to be submitted to the CPUC.

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 certain 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 March 31, 2018, the recorded regulatory liability associated with these tracked amounts totaled $67 million and $77 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 March 31, 2018, SDG&E and SoCalGas recorded regulatory liabilities of $18 million and $19 million, respectively, in anticipation of amounts that will benefit customers in future rates. SDG&E also recorded a $15 million regulatory liability at March 31, 2018 for its FERC jurisdiction 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 the filed advice letters, 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	%

As a result of the updates included in the filed advice letters, the impact of the changes to the embedded cost of debt and return on rate base is summarized below:



IMPACT OF 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.

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 expands 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 for approximately $26 million in cash bringing Sempra Energy’s indirect ownership in Oncor to 80.25 percent. The membership interests were previously held by OMI. 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.) has been 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 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, upon consummation of the Merger, 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 is comprised as follows:



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), mandatory convertible 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 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 is 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)
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 recoverable assets and liabilities 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 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 will 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.

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 we discuss in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report. As a result, we stopped depreciating the plant and classified it as held for sale.

In connection with TdM’s classification as held for sale, we recognized a $5 million income tax benefit for the three months ended March 31, 2017 for a deferred Mexican income tax liability related to the excess of the tax basis over carrying value. We continue to actively pursue the sale of TdM, which we expect to be completed in 2018.

At March 31, 2018, the carrying amounts of the major classes of assets and related liabilities held for sale associated with TdM are as follows:



ASSETS HELD FOR SALE AT MARCH 31, 2018
(Dollars in millions)
	Termoeléctrica de Mexicali
Inventories	$	10
Other current assets	64
Property, plant and equipment, net	55
Other noncurrent assets	6
Total assets held for sale	$	135

Accounts payable	$	2
Other current liabilities	38
Asset retirement obligations	5
Other noncurrent liabilities	7
Total liabilities held for sale	$	52

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 (losses) both before and net of income tax are combined and presented as Equity Losses on the Condensed Consolidated Statements of Operations. See Note 1 for a reconciliation of pretax income 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 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.

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 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 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, which we discuss in the following

paragraph, we account for our investment in Oncor Holdings under the equity method, which comprises our newly formed 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.

For the three months ended March 31, 2018, we recognized $15 million in equity earnings, net of income tax, for the period since the acquisition date. 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.

Summarized income statement information for Oncor Holdings for the period from the March 9, 2018 acquisition date is as follows:



SUMMARIZED FINANCIAL INFORMATION – ONCOR HOLDINGS
(Dollars in millions)
	March 9 - March 31, 2018
Gross revenues	$	236
Operating expense	(185		)
Income from operations	51
Interest expense	(22		)
Income tax expense	(7		)
Net income	19
Earnings	15

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 MEXICO

Sempra Mexico invested cash of $25 million and $46 million in its unconsolidated joint ventures in the three months ended March 31, 2018 and 2017, respectively.

SEMPRA LNG & MIDSTREAM

Sempra LNG & Midstream capitalized $11 million of interest in each of the three months ended March 31, 2018 and 2017 related to its investment in Cameron LNG JV, which has not commenced planned principal operations. In the three months ended March 31, 2018 and 2017, Sempra LNG & Midstream invested cash of $29 million and $1 million, respectively, and in April 2018 invested cash of $32 million, in this unconsolidated joint venture.

GUARANTEES

At March 31, 2018, we had outstanding guarantees aggregating a maximum of $4.5 billion with an aggregate carrying value of $31 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 March 31, 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 March 31, 2018 was approximately $2.2 billion. Our foreign operations have additional general purpose credit facilities aggregating $1.7 billion, with $1.3 billion available unused credit at March 31, 2018.



PRIMARY U.S. COMMITTED LINES OF CREDIT
(Dollars in millions)
	March 31, 2018
	Total facility			Commercial paper outstanding⁽¹⁾			Adjustment for combined limit			Available unused credit
Sempra Energy⁽²⁾	$	1,250		$	—		$	—		$	1,250
Sempra Global⁽³⁾	3,185			(2,826		)	—			359
California Utilities⁽⁴⁾:
SDG&E	750			(340		)	—			410
SoCalGas	750			(100		)	(90		)	560
Less: combined limit of $1 billion for both utilities	(500		)	—			90			(410		)
	1,000			(440		)	—			560
Total	$	5,435		$	(3,266	)	$	—		$	2,169


⁽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 March 31, 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 March 31, 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 March 31, 2018.



CREDIT FACILITIES IN SOUTH AMERICA AND MEXICO
(U.S. dollar-equivalent in millions)
			March 31, 2018
		Denominated in	Total facility		Amount outstanding				Available unused credit
Sempra South American Utilities⁽¹⁾:
	Peru⁽²⁾	Peruvian sol	$	455	$	(103	)	⁽³⁾	$	352
	Chile	Chilean peso	115		—				115
Sempra Mexico:
	IEnova⁽⁴⁾	U.S. dollar	1,170		(312		)		858
Total			$	1,740	$	(415	)		$	1,325


⁽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 March 31, 2018.


⁽³⁾	Includes bank guarantees of $17 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 standby letter of credit capacity with select lenders that is uncommitted and supported by reimbursement agreements. At March 31, 2018, we had approximately $498 million in standby 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 2.52 percent and 1.92 percent at March 31, 2018 and December 31, 2017, respectively. The weighted average interest rates on total short-term debt at SDG&E were 1.85 percent and 1.65 percent at March 31, 2018 and December 31, 2017, respectively. The weighted average interest rates on total short-term debt at SoCalGas were 1.75 percent and 1.64 percent at March 31, 2018 and December 31, 2017, respectively.

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 temporarily 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 are effectively subordinated to all existing and future indebtedness and other liabilities of Oncor Holdings, Oncor and their respective subsidiaries.

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.

We summarize net energy derivative volumes at March 31, 2018 and December 31, 2017 as follows:



NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
Commodity	Unit of measure	March 31, 2018	December 31, 2017
California Utilities:
SDG&E:
Natural gas	MMBtu	33	39
Electricity	MWh	3	3
Congestion revenue rights	MWh	57	59

Energy-Related Businesses:
Sempra LNG & Midstream – natural gas	MMBtu	5	3
Sempra Mexico – natural gas	MMBtu	17	4

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.

At March 31, 2018 and December 31, 2017, the net notional amounts of our interest rate derivatives, excluding joint ventures, were:



INTEREST RATE DERIVATIVES
(Dollars in millions)
	March 31, 2018			December 31, 2017
	Notional debt		Maturities	Notional debt		Maturities
Sempra Energy Consolidated:
Cash flow hedges⁽¹⁾	$	845	2018-2032	$	861	2018-2032
SDG&E:
Cash flow hedge⁽¹⁾	292		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 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.

At March 31, 2018 and December 31, 2017, the net notional amounts of our foreign currency derivatives, excluding joint ventures, were:



FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
	March 31, 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	975		2018-2019	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 at March 31, 2018 and December 31, 2017, 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)
	March 31, 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⁾	$	1		$	2		$	(12	)	$	(122	)
Derivatives not designated as hedging instruments:
Foreign exchange instruments	43			—			—			—
Commodity contracts not subject to rate recovery	64			10			(61		)	(11		)
Associated offsetting commodity contracts	(54		)	(8		)	54			8
Commodity contracts subject to rate recovery	22			98			(60		)	(123		)
Associated offsetting cash collateral	—			—			16			7
Net amounts presented on the balance sheet	76			102			(63		)	(241		)
Additional cash collateral for commodity contracts not subject to rate recovery	21			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	14			—			—			—
Total⁽⁴⁾	$	111		$	102		$	(63	)	$	(241	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments⁽³⁾	$	—		$	—		$	(8	)	$	(1	)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	20			98			(59		)	(123		)
Associated offsetting cash collateral	—			—			16			7
Net amounts presented on the balance sheet	20			98			(51		)	(117		)
Additional cash collateral for commodity contracts subject to rate recovery	12			—			—			—
Total⁽⁴⁾	$	32		$	98		$	(51	)	$	(117	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	2		$	—		$	(1	)	$	—
Net amounts presented on the balance sheet	2			—			(1		)	—
Additional cash collateral for commodity contracts subject to rate recovery	2			—			—			—
Total	$	4		$	—		$	(1	)	$	—


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


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


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


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



DERIVATIVE INSTRUMENTS ON THE 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 for the three months ended March 31:



CASH FLOW HEDGE IMPACTS
(Dollars in millions)
	Pretax gain (loss) recognized in OCI							Pretax (loss) gain reclassified from AOCI into earnings
	Three months ended March 31,							Three months ended March 31,
	2018			2017			Location	2018			2017
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments⁽¹⁾	$	54		$	16		Interest Expense	$	2		$	3
							Other Income, Net	18			—
Interest rate and foreign exchange instruments	70			(14		)	Equity Losses	(4		)	(4		)
Foreign exchange instruments	(7		)	(9		)	Revenues: Energy- Related Businesses	—			(2		)
Commodity contracts not subject to rate recovery	—			3			Revenues: Energy- Related Businesses	—			(9		)
Total	$	117		$	(4	)		$	16		$	(12	)
SDG&E:
Interest rate instruments⁽¹⁾	$	1		$	—		Interest Expense	$	(3	)	$	(3	)


⁽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 losses of $13 million, which are net of income tax benefit, that are currently recorded in AOCI (including $7 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 twelve 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 twelve 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 March 31, 2018 is approximately 14 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 18 years.

The effects of derivative instruments not designated as hedging instruments on the Condensed Consolidated Statements of Operations for the three months ended March 31 were:



UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Three months ended March 31,
	Location	2018			2017
Sempra Energy Consolidated:
Foreign exchange instruments	Other Income, Net	$	44		$	65
Commodity contracts not subject to rate recovery	Revenues: Energy-Related Businesses	(9		)	14
Commodity contracts not subject to rate recovery	Operation and Maintenance	—			(1		)
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	2			(29		)
Commodity contracts subject to rate recovery	Cost of Natural Gas	1			—
Total		$	38		$	49
SDG&E:
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	$	2		$	(29	)
SoCalGas:
Commodity contracts not subject to rate recovery	Operation and Maintenance	$	—		$	(1	)
Commodity contracts subject to rate recovery	Cost of Natural Gas	1			—
Total		$	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 March 31, 2018 and December 31, 2017 is $1 million and $6 million, respectively. At March 31, 2018, if the credit ratings of Sempra Energy were reduced below investment grade, $2 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 asset position is negligible at March 31, 2018 and in a net liability position is $1 million at December 31, 2017. At March 31, 2018, if the credit ratings of SDG&E were reduced below investment grade, a negligible amount of additional assets could be required to be posted as collateral for these derivative contracts.

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

NOTE 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 March 31, 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 three months ended March 31, 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 at March 31, 2018 and December 31, 2017 in the tables below include, other than a $9 million investment at March 31, 2018 measured at net asset value, the following:

▪

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 March 31, 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 March 31, 2018
	Level 1			Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	486		$	5	$	—	$	491
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	35			9		—		44
Municipal bonds	—			247		—		247
Other securities	—			216		—		216
Total debt securities	35			472		—		507
Total nuclear decommissioning trusts⁽¹⁾	521			477		—		998
Interest rate and foreign exchange instruments	—			46		—		46
Commodity contracts not subject to rate recovery	4			8		—		12
Effect of netting and allocation of collateral⁽²⁾	21			—		—		21
Commodity contracts subject to rate recovery	—			2		118		120
Effect of netting and allocation of collateral⁽²⁾	9			—		5		14
Total	$	555		$	533	$	123	$	1,211

Liabilities:
Interest rate and foreign exchange instruments	$	—		$	134	$	—	$	134
Commodity contracts not subject to rate recovery	7			3		—		10
Commodity contracts subject to rate recovery	23			3		157		183
Effect of netting and allocation of collateral⁽²⁾	(23		)	—		—		(23		)
Total	$	7		$	140	$	157	$	304

	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⁽²⁾	2			—		—		2
Commodity contracts subject to rate recovery	—			2		126		128
Effect of netting and allocation of collateral⁽²⁾	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⁽²⁾	(23		)	—		—		(23		)
Total	$	—		$	230	$	154	$	384


⁽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 – SDG&E
(Dollars in millions)
	Fair value at March 31, 2018
	Level 1			Level 2		Level 3		Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	486		$	5	$	—	$	491
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	35			9		—		44
Municipal bonds	—			247		—		247
Other securities	—			216		—		216
Total debt securities	35			472		—		507
Total nuclear decommissioning trusts⁽¹⁾	521			477		—		998
Commodity contracts subject to rate recovery	—			—		118		118
Effect of netting and allocation of collateral⁽²⁾	7			—		5		12
Total	$	528		$	477	$	123	$	1,128

Liabilities:
Interest rate instruments	$	—		$	9	$	—	$	9
Commodity contracts subject to rate recovery	23			2		157		182
Effect of netting and allocation of collateral⁽²⁾	(23		)	—		—		(23		)
Total	$	—		$	11	$	157	$	168

	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 March 31, 2018
	Level 1		Level 2		Level 3		Total
Assets:
Commodity contracts subject to rate recovery	$	—	$	2	$	—	$	2
Effect of netting and allocation of collateral⁽¹⁾	2		—		—		2
Total	$	2	$	2	$	—	$	4

Liabilities:
Commodity contracts subject to rate recovery	$	—	$	1	$	—	$	1
Total	$	—	$	1	$	—	$	1

	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

The 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 March 31,
	2018			2017
Balance at January 1	$	(28	)	$	(74	)
Realized and unrealized gains (losses)	4			(13		)
Allocated transmission instruments	3			—
Settlements	(19		)	(9		)
Balance at March 31	$	(40	)	$	(96	)
Change in unrealized losses relating to instruments still held at March 31	$	(8	)	$	(16	)

⁽¹⁾ Excludes the effect of 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, are 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 $20.00 per MWh to $51.30 per MWh at March 31, 2018, and $14.50 per MWh to $43.25 per MWh at March 31, 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 at March 31, 2018 and December 31, 2017:



FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
	March 31, 2018
	Carrying amount		Fair value
	Carrying amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Long-term amounts due from unconsolidated affiliates⁽¹⁾	$	627	$	—	$	606	$	41	$	647
Long-term amounts due to unconsolidated affiliates⁽²⁾	35		—		32		—		32
Total long-term debt⁽³⁾⁽⁴⁾	22,063		790		21,254		456		22,500
SDG&E:
Total long-term debt⁽⁴⁾⁽⁵⁾	$	4,848	$	—	$	4,892	$	292	$	5,184
SoCalGas:
Total long-term debt⁽⁶⁾	$	3,009	$	—	$	3,102	$	—	$	3,102

	December 31, 2017
	Carrying amount		Fair value
	Carrying amount		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⁽³⁾⁽⁴⁾	17,138		817		17,134		458		18,409
SDG&E:
Total long-term debt⁽⁴⁾⁽⁵⁾	$	4,868	$	—	$	5,073	$	295	$	5,368
SoCalGas:
Total long-term debt⁽⁶⁾	$	3,009	$	—	$	3,192	$	—	$	3,192


⁽¹⁾	Excluding accumulated interest outstanding of $35 million and $29 million at March 31, 2018 and December 31, 2017, respectively, and excluding foreign currency translation of $4 million and $35 million on a Mexican peso-denominated loan at March 31, 2018 and December 31, 2017, respectively.


⁽²⁾	Excluding negligible interest outstanding at March 31, 2018 and December 31, 2017.

⁽³⁾

Before reductions for unamortized discount (net of premium) and debt issuance costs of $206 million and $143 million at March 31, 2018 and December 31, 2017, respectively, and excluding build-to-suit and capital lease obligations of $877 million at both March 31, 2018 and December 31, 2017. 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.


⁽⁴⁾	Level 3 instruments include $292 million and $295 million at March 31, 2018 and December 31, 2017, respectively, related to Otay Mesa VIE.


⁽⁵⁾	Before reductions for unamortized discount and debt issuance costs of $45 million at both March 31, 2018 and December 31, 2017, and excluding capital lease obligations of $730 million and $732 million at March 31, 2018 and December 31, 2017, respectively.


⁽⁶⁾	Before reductions for unamortized discount and debt issuance costs of $24 million at both March 31, 2018 and December 31, 2017, and excluding capital lease obligations of $4 million and $1 million at March 31, 2018 and December 31, 2017, respectively.

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

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 Operation and Maintenance 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, ORA, 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. If approved by the CPUC, the Revised Settlement Agreement will resolve all issues under consideration in the SONGS OII and will modify 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.

The Revised Settlement Agreement is subject to CPUC approval. The parties to the Revised Settlement Agreement have agreed to exercise their best efforts to obtain CPUC approval. In the event that the CPUC fails to approve the Revised Settlement Agreement, the proceeding will remain open and subject to previous rulings in the SONGS OII, and the Amended Settlement Agreement will remain in effect, unless it is modified or set aside by the CPUC as a result of the OII proceeding.

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 would not receive upon implementation of the Revised Settlement Agreement. The Utility Shareholder Agreement is not subject to the approval of the CPUC. However, it is not effective unless and until the CPUC approves the Revised Settlement Agreement.

The timing of a ruling by the CPUC on the Joint Motion for Adoption of the Settlement Agreement is unclear. There is no assurance that the Revised Settlement Agreement will be adopted or that the Amended Settlement Agreement will not be modified or set aside as a result of the OII proceeding, which could result in a substantial reduction in our expected recovery or in no recovery and payments to customers. These outcomes could have a material adverse effect on Sempra Energy’s and SDG&E’s results of operations, financial condition and cash flows.

Disallowances, Refunds and Recoveries

If the Revised Settlement Agreement is approved by the CPUC, SDG&E and Edison will cease rate recovery of SONGS costs as authorized under the Amended Settlement Agreement as of the date their combined remaining SONGS regulatory assets equal $775 million (the Cessation Date). Currently, the estimated Cessation Date is December 19, 2017. The Cessation Date is partly dependent on the outcome of Edison’s pending request to the CPUC, in a separate proceeding, for approval to apply certain proceeds received from the DOE to reduce Edison’s SONGS regulatory asset. If this request is rejected by the CPUC, then the estimated Cessation Date will be April 21, 2018. In either case, 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 and Edison will refund to customers SONGS-related amounts recovered in rates after the Cessation Date.

In the event that the CPUC takes an action that has the effect of invalidating the Utility Shareholder Agreement, SDG&E may, in its discretion, withdraw from the Revised Settlement Agreement, in which case Edison shall remain a party to the Revised Settlement Agreement, but the Revised Settlement Agreement shall be terminated as to SDG&E. In such a scenario, SDG&E would return to its litigation position before the CPUC in the SONGS OII that existed prior to the Revised Settlement Agreement.

Pursuant to the CPUC’s rules, no settlement becomes binding unless the CPUC approves the settlement based on a finding that it is reasonable in light of the whole record, consistent with law, and in the public interest. The CPUC has discretion to approve or disapprove a settlement, or to condition its approval on changes to the settlement, which the parties may accept or reject, negotiating in good faith to seek a resolution acceptable to all parties. CPUC rules do not provide for any fixed time period for the CPUC to act on proposed settlements.

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 would no longer recover because of the Revised Settlement Agreement. In exchange for Edison’s reimbursement, the parties will mutually release each other from the “SONGS Issues,” a defined term that consists of 18 broad categories. The effect of the agreement is that the parties will release 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 becomes effective only upon CPUC approval of the Revised Settlement Agreement. Edison’s payment obligation commences 30 days after the first fiscal quarter in which the CPUC approves the Revised Settlement Agreement, 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 March 31, 2018, SDG&E has a receivable from Edison totaling $153 million, $42 million classified as current and $111 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, which SDG&E believes is now no longer probable of recovery.

Assuming the Revised Settlement Agreement is approved, SDG&E and Sempra Energy do not expect that implementation of the Revised Settlement Agreement in combination with the Utility Shareholder Agreement will have a material adverse impact on either company. However, until the CPUC approves the Revised Settlement Agreement as proposed, there can be no assurance that the SONGS OII proceeding will conclude as contemplated by SDG&E in accordance with the Revised Settlement Agreement and the Utility Shareholder Agreement, or that the CPUC will not order refunds to customers above those contemplated by the Amended Settlement Agreement, or take other action that may be adverse to SDG&E and Sempra Energy. Such alternative outcomes could have a material adverse effect on SDG&E’s and Sempra Energy’s results of operations, financial condition and cash flows.

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 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 2016 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 March 31, 2018:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies⁽¹⁾	$	44	$	—	$	—		$	44
Municipal bonds⁽¹⁾	245		4		(2		)	247
Other securities⁽²⁾	217		2		(3		)	216
Total debt securities	506		6		(5		)	507
Equity securities	172		321		(2		)	491
Cash and cash equivalents	19		—		—			19
Total	$	697	$	327	$	(7	)	$	1,017
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 2018-2048.


⁽²⁾	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 March 31,
	2018			2017
Proceeds from sales⁽¹⁾	$	210		$	357
Gross realized gains	4			45
Gross realized losses	(3		)	(5		)


⁽¹⁾	Excludes securities that are held to maturity.

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 by 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. We expect the request for reconsideration to extend the claims process by a minimum of two months. It is unclear whether the DOE will approve the request and how much of the disputed amount will be recovered, if any.

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 is 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 estimate with reasonable certainty the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed applicable insurance coverage and could materially adversely affect our business, cash flows, results of operations, financial condition and prospects. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.

At March 31, 2018, loss contingency accruals for legal matters, including associated legal fees, that are probable and estimable were $144 million for Sempra Energy Consolidated, including $3 million for SDG&E and $90 million for SoCalGas. Amounts for Sempra Energy and SoCalGas include $85 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, except one appeal that remains pending after judgment in the trial court. SDG&E does not expect additional plaintiffs to file lawsuits given the applicable statutes of limitation, but could receive additional settlement demands and damage estimates from the remaining plaintiff until the case is resolved. SDG&E maintains reserves for the wildfire litigation and adjusts these reserves as information becomes available and amounts are estimable.

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. The CPUC may grant a rehearing, modify its decision, or deny the request and affirm its original decision. We will appeal the decision with the California Courts of Appeal seeking to reverse the CPUC’s decision, if necessary.

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), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Cost Estimates and Accounting Impact. At March 31, 2018, SoCalGas estimates that its costs related to the Leak are $954 million, which includes $928 million of costs recovered or probable of recovery from insurance. Of the $954 million of estimated costs, approximately 60 percent is for the temporary relocation program (including cleaning costs and certain labor costs). Other estimated costs include amounts for efforts to control the well, stop the Leak, stop or reduce the emissions, and the estimated cost of the root cause analysis being conducted by an independent third party to investigate the cause of the Leak. The remaining portion of the $954 million includes legal costs incurred to defend litigation, the estimated costs to settle certain actions, 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. The $954 million represents management’s best estimate of these costs related to the Leak. Of these costs, a substantial portion has been paid and $122 million is accrued as Reserve for Aliso Canyon Costs as of March 31, 2018 on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets for amounts expected to be paid after March 31, 2018.

As of March 31, 2018, we recorded the expected recovery of the costs described in the immediately preceding paragraph related to the Leak of $447 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 $481 million of insurance proceeds we received through March 31, 2018 related to control-of-well expenses, lost gas and temporary relocation costs. If we were to conclude that this receivable or a portion of it was no longer probable of recovery from insurers, some or all of this receivable 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 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 above amounts 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 of $954 million does not include certain other costs expensed by Sempra Energy through March 31, 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 four kinds of insurance policies that together 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 natural 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 control-of-well expenses, lost gas and temporary relocation costs. 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 March 31, 2018, SoCalGas’ estimated costs related to the Leak of $954 million include $928 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 $954 million cost estimate could be material. To the extent not covered by insurance (including any costs in excess of applicable policy limits), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Governmental Investigations and Civil and Criminal Litigation. Various governmental agencies, including 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 May 3, 2018, 381 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 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.

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 residing near the Aliso Canyon natural gas storage facility who objected 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), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

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 a high level Phase 1 schedule contemplating public participation hearings and workshops beginning in April 2017, but no hearings until Phase 2.

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 does 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. Under section 455.5, hearings on the investigation are to be held, if necessary, in conjunction with SoCalGas’ 2019 GRC proceeding. If the CPUC determines that all or any portion of the facility was out of service for nine consecutive months, the amount of any refund to ratepayers and the inability to earn a return on those assets could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

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.

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. The CARB program requires that reductions in short-lived climate pollutants and other GHG be at least equivalent to the amount of the emissions from the Leak, and that the amount of reductions required be derived using the global warming potential based on a 20-year term (rather than the 100-year term the CARB and other state and federal agencies use in regulating emissions), resulting in a target of approximately 9,000,000 metric tons of carbon dioxide equivalent. CARB’s program also calls for all of the mitigation to occur in California over the next five to ten years without the use of allowances or offsets. 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. We have not agreed with CARB’s estimate of methane released and continue to work with CARB on developing a mitigation plan.

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 were made in 2017 and in February and March of 2018 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 CPUC additionally issued a directive to SoCalGas to maintain a range of working gas in the Aliso Canyon natural gas storage facility above 14.8 Bcf at all times, with a target of 23.6 Bcf (approximately 28 percent of its maximum capacity), and later amended the directive to require that the range be maintained from zero Bcf to 24.6 Bcf of working gas. 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 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.

If the Aliso Canyon natural gas storage facility were determined to have been out of service for any meaningful period of time or 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 March 31, 2018, the Aliso Canyon natural gas storage facility has a net book value of $656 million, including $259 million of construction work in progress for the project to construct 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.

Cases involving two 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 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. 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. 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. RBS, our partner in the joint venture, paid an £86 million assessment 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 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 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 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 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. Trial of the matter has been set for the summer of 2018. 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.

Our remaining investment in RBS Sempra Commodities of $67 million at March 31, 2018 is accounted for under the equity method and reflects remaining distributions expected to be received from the partnership as it is liquidated. The timing and amount of distributions may be impacted by these matters.

Certain EFH subsidiaries that we acquired as part of the Merger are defendants in approximately 140 personal injury lawsuits brought in state courts throughout the U.S. 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.

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 three 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

Sempra LNG & Midstream’s natural gas purchase and transportation commitments have decreased by $54 million since December 31, 2017, primarily due to payments on existing contracts and changes in forward natural gas prices in the first three months of 2018. Net future payments are expected to decrease by $62 million in 2018, and increase by $3 million in 2019, $2 million in 2020, $2 million in 2021, and $1 million in 2022 compared to December 31, 2017.

LNG Purchase Agreement

Sempra LNG & Midstream has a 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 March 31, 2018, the commitment amount is expected to decrease by $112 million in 2018, $55 million in 2019, $42 million in 2020, $40 million in 2021, $30 million in 2022 and $110 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 three 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 three months of 2018, significant net increases to contractual commitments at Sempra Mexico were $94 million, primarily for contracts related to the construction of liquid fuels terminals. Net future payments under these contractual commitments are expected to increase by $91 million in 2018, $2 million in 2019 and $1 million thereafter compared to December 31, 2017.

Other Commitments

Sempra Mexico

In the first three months of 2018, significant net increases to contractual commitments at Sempra Mexico were $81 million, primarily for contracts for the construction of renewables projects. Net future payments under these contractual commitments are expected to increase by $53 million in 2018 and $28 million in 2019 compared to December 31, 2017.

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. In February 2016, management approved a plan to market and sell the TdM natural gas-fired power plant located in Mexicali, Baja California, as we discuss in Note 5.


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


▪	Sempra LNG & Midstream develops, owns and operates, or holds interests in, a terminal for the import and export of LNG and sale of natural gas, and natural gas pipelines, storage facilities and marketing operations, all within the U.S.

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.

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

The following tables show selected information by segment from our 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.



SEGMENT INFORMATION
(Dollars in millions)
	Three months ended March 31,
	2018			2017
REVENUES
SDG&E	$	1,055		$	1,057
SoCalGas	1,126			1,241
Sempra South American Utilities	426			412
Sempra Mexico	308			264
Sempra Renewables	25			22
Sempra LNG & Midstream	104			132
Adjustments and eliminations	(1		)	—
Intersegment revenues⁽¹⁾	(81		)	(97		)
Total	$	2,962		$	3,031
INTEREST EXPENSE
SDG&E	$	52		$	49
SoCalGas	27			25
Sempra South American Utilities	10			9
Sempra Mexico	30			32
Sempra Renewables	5			4
Sempra LNG & Midstream	8			11
All other	112			68
Intercompany eliminations	(28		)	(29		)
Total	$	216		$	169
INTEREST INCOME
SDG&E	$	1		$	—
Sempra South American Utilities	6			5
Sempra Mexico	15			2
Sempra Renewables	2			1
Sempra LNG & Midstream	13			17
All other	14			—
Intercompany eliminations	(18		)	(19		)
Total	$	33		$	6
DEPRECIATION AND AMORTIZATION
SDG&E	$	166		$	163
SoCalGas	135			126
Sempra South American Utilities	14			13
Sempra Mexico	43			36
Sempra Renewables	13			9
Sempra LNG & Midstream	11			10
All other	4			3
Total	$	386		$	360
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	56		$	90
SoCalGas	59			98
Sempra South American Utilities	20			19
Sempra Mexico	155			142
Sempra Renewables	(7		)	(11		)
Sempra LNG & Midstream	12			1
All other	(6		)	(44		)
Total	$	289		$	295



SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
	Three months ended March 31,
	2018			2017
EQUITY EARNINGS (LOSSES)
Equity earnings before income tax:
Sempra Renewables	$	5		$	2
Sempra LNG & Midstream	—			1
	5			3
Equity earnings (losses) net of income tax:
Sempra Texas Utility	15			—
Sempra South American Utilities	1			1
Sempra Mexico	(41		)	(9		)
	(25		)	(8		)
Total	$	(20	)	$	(5	)
EARNINGS (LOSSES) ATTRIBUTABLE TO COMMON SHARES
SDG&E	$	170		$	155
SoCalGas⁽²⁾	225			203
Sempra Texas Utility	15			—
Sempra South American Utilities	46			47
Sempra Mexico	20			48
Sempra Renewables	21			11
Sempra LNG & Midstream	(16		)	1
All other⁽²⁾	(134		)	(24		)
Total	$	347		$	441
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E	$	475		$	418
SoCalGas	403			357
Sempra South American Utilities	56			43
Sempra Mexico	59			94
Sempra Renewables	31			69
Sempra LNG & Midstream	6			3
All other	5			8
Total	$	1,035		$	992

	March 31, 2018			December 31, 2017
ASSETS
SDG&E	$	18,017		$	17,844
SoCalGas	14,462			14,159
Sempra Texas Utility	9,176			—
Sempra South American Utilities	4,154			4,060
Sempra Mexico	8,798			8,554
Sempra Renewables	2,764			2,898
Sempra LNG & Midstream	4,904			4,872
All other	964			915
Intersegment receivables	(2,754		)	(2,848		)
Total	$	60,485		$	50,454
EQUITY METHOD AND OTHER INVESTMENTS
Sempra Texas Utility	$	9,176		$	—
Sempra South American Utilities	17			16
Sempra Mexico	613			624
Sempra Renewables	798			813
Sempra LNG & Midstream	1,085			997
All other	77			77
Total	$	11,766		$	2,527


⁽¹⁾	Revenues for reportable segments include intersegment revenues of $1 million, $17 million, $29 million and $34 million for the three months ended March 31, 2018 and $1 million, $18 million, $25 million and $53 million for the three months ended March 31, 2017 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG & Midstream, respectively.


⁽²⁾	After preferred dividends.

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 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 operating units invest in, develop and operate energy infrastructure, and provide electric and gas services to customers in North and South America. We have two principal operating units, Sempra Utilities and Sempra Infrastructure.

Sempra Utilities includes our SDG&E, SoCalGas, Sempra Texas Utility and Sempra South American Utilities segments. Sempra Texas Utility 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.” We discuss the acquisition in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

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

Additional information about our operating units and their respective reportable segments is provided in “Item 1. Business” in the Annual Report.

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 Infrastructure operating unit. All references to “Sempra Utilities” and “Sempra Infrastructure,” and to their respective reportable segments, are not intended to refer to any legal entity with the same or similar name.

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.

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 more than 134,000 miles of transmission and distribution lines. 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. Oncor’s distribution customers consist 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 comprises 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 15,919 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 120,000 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 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 does not have the prior approval of the appropriate regulatory authority (i.e., the PUCT or the municipality with original jurisdiction).

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.

PUCT substantive rules allow Oncor to update its transmission rates periodically to reflect changes in invested capital. This “capital tracker” provision encourages investment in the transmission system to help ensure reliability and efficiency by allowing for timely recovery of and return on new transmission investments.

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, assist 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 protocol.

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.

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 requires Oncor to record a regulatory liability until the new authorized regulatory capital structure is met to reflect Oncor’s actual capitalization prior to achieving the authorized capital structure. Once the authorized capital structure is attained, the regulatory liability will be returned to customers through the capital structure refund mechanism as approved by the PUCT. Oncor implemented the regulatory liability as of November 27, 2017.

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.

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 decreased by $94 million (21%) to $347 million in the three months ended March 31, 2018, while diluted EPS decreased by $0.42 per share (24%) to $1.33 per share. The decrease in EPS included $0.04 attributable to an increase in the weighted average number of common shares outstanding, primarily due to the common stock issuances in the first quarter of 2018 that we discuss in Note 1 of the Notes to Condensed Consolidated Financial Statements herein. Our earnings 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 March 31,
	2018			2017
Sempra Utilities:
SDG&E	$	170		$	155
SoCalGas⁽¹⁾	225			203
Sempra Texas Utility	15			—
Sempra South American Utilities	46			47
Sempra Infrastructure:
Sempra Mexico	20			48
Sempra Renewables	21			11
Sempra LNG & Midstream	(16		)	1
Parent and other⁽¹⁾⁽²⁾	(134		)	(24		)
Earnings	$	347		$	441


⁽¹⁾	After preferred dividends.


⁽²⁾	Includes after-tax interest expense ($81 million and $41 million for the three months ended March 31, 2018 and 2017, respectively), intercompany eliminations recorded in consolidation and certain corporate costs.

SDG&E

The increase in earnings of $15 million (10%) in the three months ended March 31, 2018 was primarily due to:


▪	$14 million increased margin as a result of revised electric distribution seasonality factors in 2018;


▪	$12 million higher CPUC base operating margin authorized for 2018, of which $9 million relates to the lower federal income tax rate in 2018; and


▪	$6 million higher earnings from electric transmission operations, of which $2 million relates to the lower federal income tax rate in 2018; offset by


▪	$8 million higher net interest expense, of which $6 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

The increase in earnings of $22 million (11%) in the three months ended March 31, 2018 was primarily due to:


▪	$31 million higher CPUC base operating margin authorized for 2018, net of expenses including depreciation. Of this increase, $26 million relates to the lower federal income tax rate in 2018; and


▪	$4 million higher PSEP earnings; offset by


▪	$7 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


▪	$4 million income tax expense in 2018 associated with excess tax deficiencies related to share-based compensation.

Sempra Texas Utility

In the three months ended March 31, 2018, earnings of $15 million at our Sempra Texas Utility segment represent equity earnings from our investment in Oncor Holdings since we acquired it on March 9, 2018. We discuss the acquisition in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra South American Utilities

Earnings for the three months ended March 31, 2018 were consistent with earnings for the same period in 2017.

Sempra Mexico

The decrease in earnings of $28 million in the three months ended March 31, 2018 was primarily due to:


▪	$35 million lower earnings from the recognition of AFUDC related to equity in the first quarter of 2017, of which $18 million related to a cumulative amount recognized when regulatory recovery became probable for the Ojinaga and San Isidro pipelines. These projects were completed in the first half of 2017;


▪	$12 million higher income tax expense in 2018 from the outside basis differences in joint venture investments; and


▪	$5 million higher unfavorable impact from foreign currency and inflation effects net of gains on foreign currency derivatives, comprised of:


◦	in 2018, $95 million unfavorable foreign currency and inflation effects, offset by $32 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


◦	in 2017, $102 million unfavorable foreign currency and inflation effects, offset by $44 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


▪	$12 million higher pipeline operational earnings, primarily attributable to assets placed in service in the second quarter of 2017; and


▪	$2 million losses attributable to noncontrolling interests at IEnova in 2018 compared to $5 million earnings in 2017.

Sempra Renewables

The increase in earnings of $10 million in the three months ended March 31, 2018 was primarily due to $9 million higher earnings from our wind tax equity investments, primarily driven by the impact of the TCJA on NCI allocations computed using the HLBV method.

Sempra LNG & Midstream

The decrease in earnings of $17 million in the three months ended March 31, 2018 was primarily due to:


▪	$11 million lower results from midstream activities primarily driven by changes in natural gas prices, of which $1 million relates to the lower federal income tax rate in 2018; and


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

Parent and Other

The increase in losses of $110 million in the three months ended March 31, 2018 was primarily due to:


▪	$25 million income tax expense in 2018 compared to $11 million income tax benefit in 2017, which included $16 million income tax expense in 2018 to adjust TCJA provisional amounts recorded in 2017 primarily related to withholding tax on our expected future repatriation of foreign undistributed earnings;


▪	$30 million increase in net interest expense, of which $12 million relates to a lower tax rate in 2018;


▪	$28 million of mandatory convertible preferred stock dividends; and


▪	$4 million investment losses in 2018 compared to $10 million investment gains in 2017 on dedicated assets in support of our executive retirement and deferred compensation plans, net of lower deferred compensation expense associated with these investments.

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.

The table below reconciles 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, for the three months ended March 31, 2018 and 2017. SDG&E and SoCalGas did not have any adjustments to earnings for the three months ended March 31, 2018 or 2017.



SEMPRA ENERGY ADJUSTED EARNINGS AND ADJUSTED EPS
(Dollars in millions, except per share amounts)
	Income tax expense (benefit)⁽¹⁾			Non-controlling interests		Earnings			Diluted EPS
	Three months ended March 31, 2018
Sempra Energy GAAP Earnings						$	347		$	1.33
Excluded item:
Impact from the TCJA	$	25		$	—	25			0.10
Sempra Energy Adjusted Earnings						$	372		$	1.43
Weighted-average number of shares outstanding, diluted (thousands)									259,490
	Three months ended March 31, 2017
Sempra Energy GAAP Earnings						$	441		$	1.75
Excluded item:
Deferred income tax benefit associated with TdM	$	(5	)	$	2	(3		)	(0.01		)
Sempra Energy Adjusted Earnings						$	438		$	1.74
Weighted-average number of shares outstanding, diluted (thousands)									252,246


⁽¹⁾	Income taxes associated with TdM were calculated based on the applicable statutory tax rate, including translation from historic to current exchange rates.

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 through rates.

▪

permits the cost of natural gas purchased for core customers (primarily residential and small commercial and industrial customers) to be passed through to customers in rates substantially as incurred. However, SoCalGas’ GCIM provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in 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, 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 March 31,
	2018			2017
Electric revenues:
SDG&E	$	884		$	875
Sempra South American Utilities	408			390
Eliminations and adjustments⁽¹⁾	(2		)	(2		)
Total	1,290			1,263
Natural gas revenues:
SoCalGas	1,126			1,241
SDG&E	171			182
Sempra Mexico	28			30
Eliminations and adjustments⁽¹⁾	(17		)	(18		)
Total	1,308			1,435
Total utilities revenues	$	2,598		$	2,698
Cost of electric fuel and purchased power:
SDG&E	$	274		$	261
Sempra South American Utilities	275			266
Eliminations and adjustments⁽¹⁾	(3		)	—
Total	$	546		$	527
Cost of natural gas:
SoCalGas	$	289		$	408
SDG&E	50			65
Sempra Mexico	13			19
Eliminations and adjustments⁽¹⁾	(4		)	(7		)
Total	$	348		$	485


⁽¹⁾	Includes eliminations of intercompany activity.

Electric Revenues and Cost of Electric Fuel and Purchased Power

In the three months ended March 31, 2018, our electric revenues increased by $27 million (2%) remaining at $1.3 billion due to:


▪	$18 million increase at Sempra South American Utilities, which included:


◦	$21 million higher rates at Luz del Sur and Chilquinta Energía, and


◦	$17 million due to foreign currency exchange rate effects, offset by


◦	$18 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


▪	$9 million increase at SDG&E, which included:


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


◦	$13 million higher cost of electric fuel and purchased power, which we discuss below, and


◦	$8 million increase in 2018 due to an increase in rates permitted under the attrition mechanism in the 2016 GRC FD, offset by


◦	$15 million revenue requirement deferral due to the effect of the TCJA, and


◦	$6 million higher non-service component of net periodic benefit credit in 2018, which fully offsets in Other Income.

Our utilities’ cost of electric fuel and purchased power increased by $19 million (4%) to $546 million in the three months ended March 31, 2018 primarily due to:


▪	$13 million increase at SDG&E primarily due to higher electricity market costs, offset by lower renewable generation costs due to decrease in solar and wind production; and


▪	$9 million increase at Sempra South American Utilities, which included:


◦	$12 million due to foreign currency exchange rate effects, and


◦	$11 million higher prices at Luz del Sur, offset by


◦	$14 million lower volumes at Luz del Sur.

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 March 31,
	2018		2017
SoCalGas	$	2.92	$	3.70
SDG&E	3.54		4.24

In the three months ended March 31, 2018, Sempra Energy’s natural gas revenues decreased by $127 million (9%) to $1.3 billion primarily due to:


▪	$115 million decrease at SoCalGas, which included:


◦	$119 million decrease in cost of natural gas sold, which we discuss below,


◦	$22 million higher non-service component of net periodic benefit credit in 2018, which fully offsets in Other Income,


◦	$19 million revenue requirement deferral due to the effect of the TCJA,


◦	$10 million lower cost of capital in 2018 due to the CPUC decision reducing ROE from 10.10 percent in 2017 to 10.05 percent in 2018, and


◦	$3 million lower revenues from capital projects, including $15 million decrease for advanced metering infrastructure, offset by $5 million increase for PSEP and $7 million increase for other capital projects, offset by


◦	$33 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in O&M, and


◦	$24 million increase due to 2018 attrition; and


▪	$11 million decrease at SDG&E, which includes a $15 million decrease in cost of natural gas sold, discussed below.

Our cost of natural gas decreased by $137 million (28%) to $348 million primarily due to:


▪	$119 million decrease at SoCalGas due to $77 million from lower average gas prices and $42 million from lower volumes driven by weather; and


▪	$15 million decrease at SDG&E due to $10 million from lower average gas prices and $5 million from lower volumes driven by weather.

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 March 31,
	2018			2017
REVENUES
Sempra South American Utilities	$	18		$	22
Sempra Mexico	280			234
Sempra Renewables	25			22
Sempra LNG & Midstream	104			132
Eliminations and adjustments⁽¹⁾	(63		)	(77		)
Total revenues	$	364		$	333
COST OF SALES⁽²⁾
Cost of natural gas, electric fuel and purchased power:
Sempra South American Utilities	$	5		$	4
Sempra Mexico	58			51
Sempra LNG & Midstream	65			88
Eliminations and adjustments⁽¹⁾	(59		)	(76		)
Total	$	69		$	67
Other cost of sales:
Sempra South American Utilities	$	13		$	15
Sempra Mexico	3			3
Sempra LNG & Midstream	5			7
Eliminations and adjustments⁽¹⁾	(3		)	(3		)
Total	$	18		$	22


⁽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 March 31, 2018, revenues from our energy-related businesses increased by $31 million (9%) to $364 million primarily due to:


▪	$46 million increase at Sempra Mexico primarily due to:


◦	$25 million higher revenues primarily due to pipeline assets placed in service in the second quarter of 2017,


◦	$13 million increase due to higher power prices and volumes at TdM, and


◦	$5 million higher revenues from the marketing business, primarily due to higher customer base offset by lower natural gas prices and volumes; and


▪	$14 million from lower intercompany eliminations associated with sales between Sempra LNG & Midstream and Sempra Mexico; offset by


▪	$28 million decrease at Sempra LNG & Midstream primarily due to:


◦	$24 million 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, and


◦	$18 million from natural gas marketing activities primarily from changes in natural gas prices, offset by


◦	$12 million from LNG sales to Cameron LNG JV in January 2018.

In the three months ended March 31, 2018, the cost of natural gas, electric fuel and purchased power for our energy-related businesses increased by $2 million (3%) to $69 million primarily due to:


▪	$17 million lower intercompany eliminations of costs associated with 2017 indemnity payments from Sempra LNG & Midstream to Sempra Mexico; and

100


▪	$7 million increase at Sempra Mexico mainly due to higher volumes at TdM and higher customer base at the marketing business; offset by


▪	$23 million decrease at Sempra LNG & Midstream primarily due to indemnity payments to Sempra Mexico in 2017.

Operation and Maintenance

Our O&M increased by $62 million (9%) to $781 million in the three months ended March 31, 2018 primarily due to:


▪	$28 million increase at SoCalGas, which included:


◦	$33 million higher expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses), offset by


◦	$5 million lower non-refundable operating costs, including labor, contract services and administrative and support costs;


▪	$17 million increase at SDG&E, which included:


◦	$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


◦	$9 million higher non-refundable operating costs, including labor, contract services and administrative and support costs; and


▪	$6 million increase at Sempra Renewables, primarily due to solar and wind assets placed in service in 2017 and higher general and administrative costs.

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 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 decreased by $21 million to $153 million in the three months ended March 31, 2018 primarily due to:


▪	$45 million decrease in equity-related AFUDC mainly from completion of the Ojinaga, San Isidro and Sonora pipeline projects in 2017; and


▪	$1 million investment loss in 2018 on dedicated assets in support of our executive retirement and deferred compensation plans compared to a $16 million investment gain in 2017; offset by


▪	$27 million higher non-service component of net periodic benefit credit in 2018, including $5 million at SDG&E and $22 million at SoCalGas; and


▪	$19 million higher gains in 2018 from interest rate and foreign exchange instruments and foreign currency transactions primarily due to:


◦	$39 million foreign currency gain in 2018 on a Mexican peso-denominated loan to the IMG joint venture, offset by


◦	$21 million lower gains in 2018 on foreign currency derivatives as a result of fluctuation of the Mexican peso.

Interest Expense

Interest expense increased by $47 million (28%) to $216 million in the three months ended March 31, 2018 primarily due to long-term debt issuances at Parent and other in 2018, primarily to finance the Merger.

Income Taxes

The table below shows the income tax expense and ETR for Sempra Energy, SDG&E and SoCalGas.



INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Pretax income		Income tax expense		ETR		Pretax income		Income tax expense		ETR
	Three months ended March 31,
	2018						2017
Sempra Energy Consolidated⁽¹⁾	$	672	$	289	43	%	$	755	$	295	39	%
SDG&E	225		56		25		247		90		36
SoCalGas	284		59		21		301		98		33

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⁽¹⁾	Sempra Energy's pretax income represents Income Before Income Taxes and Equity Losses of Unconsolidated Subsidiaries plus equity earnings before income tax of $5 million and $3 million in the three months ended March 31, 2018 and 2017, respectively. 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

The decrease in income tax expense in the three months ended March 31, 2018 was due to lower pretax income offset by a higher ETR. The higher ETR was primarily due to:


▪	$25 million income tax expense to adjust provisional estimates recorded in 2017 for the effects of TCJA;


▪	$13 million higher income tax expense associated with excess tax deficiencies related to share-based compensation; and


▪	$8 million income tax expense associated with the global intangible low-tax income provisions of the TCJA; offset by


▪	$36 million lower income tax expense from the lower U.S. statutory corporate federal income tax rate in 2018; and


▪	$3 million lower income tax expense from foreign currency and inflation effects in the first quarter of 2018.

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

The decrease in SDG&E’s income tax expense in the three months ended March 31, 2018 was primarily due to a lower ETR and lower pretax income. The lower ETR was primarily due to $24 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 expense in the three months ended March 31, 2018 was primarily due to a lower ETR and lower pretax income. The lower ETR was primarily due to $29 million lower income tax expense from the lower U.S. statutory corporate federal income tax rate in 2018.

Equity Losses

In the three months ended March 31, 2018, our equity losses increased by $15 million primarily due to:


▪	$32 million increase in equity losses, net of income tax, at Sempra Mexico primarily at the IMG joint venture due to a $39 million foreign currency loss on its peso-denominated loan from Sempra Mexico; offset by


▪	$15 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.

Losses (Earnings) Attributable to Noncontrolling Interests

Losses attributable to NCI for the three months ended March 31, 2018 were $17 million compared to earnings attributable to NCI of $11 million for the same period in 2017. The change was primarily due to:


▪	$18 million higher pretax losses attributed to tax equity investors at Sempra Renewables; and


▪	$2 million losses attributable to NCI at Sempra Mexico in 2018 compared to earnings of $5 million in 2017.

Mandatory Convertible Preferred Stock Dividends

In the three months ended March 31, 2018, our board of directors declared a dividend of $28 million, or $1.60 per share, on our mandatory convertible preferred stock for the period from January 9, 2018 (the issuance date) to April 15, 2018 (the first scheduled dividend payment date).

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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)
	First quarter 2018 compared to first quarter 2017
Higher earnings from foreign currency translation:
Sempra South American Utilities	$	2

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 March 31,
	2018			2017			2018			2017
Other income, net⁽¹⁾	$	153		$	174		$	92		$	75
Income tax expense	(289		)	(295		)	(94		)	(97		)
Equity losses	(20		)	(5		)	(51		)	(13		)
Net income	358			452			(64		)	(61		)
Earnings attributable to common shares	347			441			(31		)	(27		)


⁽¹⁾	Total reported amount for the three months ended March 31, 2017 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 tax equity and 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 March 31, 2018. Our foreign operations have additional general purpose credit facilities aggregating $1.7 billion, with $1.3 billion available unused credit at March 31, 2018.

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AVAILABLE FUNDS AT MARCH 31, 2018
(Dollars in millions)
	Sempra Energy Consolidated		SDG&E		SoCalGas
Unrestricted cash and cash equivalents⁽¹⁾	$	239	$	9	$	11
Available unused credit⁽²⁾⁽³⁾	2,169		410		560


⁽¹⁾	Amounts at Sempra Energy Consolidated include $186 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.

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 tax equity and 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 related to our acquisition of our investment in Oncor Holdings 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 Infrastructure businesses before we would reduce funds necessary for the ongoing needs of our utilities. We could also raise funds through the redeployment of capital through sales or monetization of assets. 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.

Our short-term debt is primarily used 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 three months of 2018. At our California Utilities, short-term debt is used 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

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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 currently anticipate electing to use our existing NOLs to offset the deemed repatriation tax. However, as provided under the TCJA, at the time of filing our tax return in 2018, should we determine that we will pay the deemed repatriation tax over a period of eight years instead of utilizing our NOLs, our income tax expense and cash tax payments would increase.

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 March 31, 2018, Sempra Energy has provided loans to unconsolidated affiliates totaling $666 million, and has received a $35 million loan from an unconsolidated affiliate, 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 and paid common stock dividends of $450 million in the year ended December 31, 2017. SDG&E’s dividends on common stock declared on an annual historical basis may not be indicative of future declarations, and could be impacted over the next few years in order for SDG&E to maintain its authorized capital structure while managing its capital investment program (over $1.2 billion in 2018).

As a result of SoCalGas’ capital investment program of over $1 billion per year, SoCalGas has not declared or paid common stock dividends since 2015. SoCalGas’ common stock dividends in the next few years will be impacted by its ability to maintain its authorized capital structure while managing its capital investment program (approximately $1.2 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. The CPUC authorized an ERRA Trigger mechanism in conjunction with California state law that allows for recovery of ERRA balances that exceed 5 percent of the prior year’s electric commodity revenues. In August 2017, the CPUC approved SDG&E’s request to amortize $120 million in rates over a 14-month period beginning November 2017. SDG&E’s ERRA balance was undercollected by $100 million and $51 million at March 31, 2018 and December 31, 2017, respectively. The increase in the ERRA undercollected balance in 2018 was primarily due to lower than forecasted electric volume in conjunction with seasonalized electric rates.

▪

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 $103 million and $112 million at March 31, 2018 and December 31, 2017, respectively. The undercollection is driven by lower than forecasted electric volumes sold in 2018 and 2017.

Similarly, SoCalGas’ “Commodity – gas, including transportation” balancing accounts include:

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▪

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 $213 million and $164 million at March 31, 2018 and December 31, 2017, respectively.

SDG&E

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), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations. 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. In addition, if it is determined that the Aliso Canyon natural gas storage facility was out of service for more than nine consecutive months, we may be unable to recover this investment in rates.

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), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Sempra Texas Utility

As we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein, on March 9, 2018, Sempra Energy completed the acquisition of an indirect, 100-percent interest in Oncor Holdings, which owned an 80.03-percent interest in Oncor, and other EFH assets and liabilities unrelated to Oncor, pursuant to the Merger Agreement with EFH. We paid Merger Consideration of $9.45 billion in cash, $31 million representing an adjustment for dividends and payments pursuant to a tax sharing agreement with Oncor and Oncor Holdings, $26 million in cash to acquire an additional 0.22 percent of the outstanding membership interests in Oncor from OMI (which 0.22 percent interest is now owned by Oncor Holdings), bringing our indirect ownership in Oncor to 80.25 percent, and approximately $59 million in associated transaction costs included in the basis of our investment in Oncor Holdings (collectively, the total purchase price).

As we discuss in Notes 1 and 7 of the Notes to Condensed Consolidated Financial Statements herein, our registered public offerings of common stock (including shares offered pursuant to forward sale agreements), mandatory convertible 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 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 of forward sales under the forward sale agreements by delivery of 8,556,630 shares of our common stock. An additional approximately $1.6 billion may be settled in our common stock pursuant to forward sales under the forward sale agreements. 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.

Upon closing, our funding of the total purchase price was comprised of approximately 31 percent equity and approximately 69 percent debt, which does not include an additional $1.6 billion that we may settle in our common stock pursuant to forward sale

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agreements. We intend to ultimately fund the total purchase price with approximately 65 percent equity and approximately 35 percent debt, including the net proceeds from the offerings in January 2018 and the forward equity sale settlements in March 2018. We may also 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. The 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. However, 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 multiple 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. We contributed $117 million in cash, commensurate with our ownership interest, to Oncor on April 23, 2018.

We anticipate that the Merger will have a positive impact on our consolidated results of operations. This expectation is based on current market conditions and is subject to a number of assumptions, estimates, projections and other uncertainties, including assumptions regarding the results of operations of the combined company after the Merger, the relative mix and timing of debt and equity financing obtained to ultimately fund the Merger Consideration, and the prices and interest rates of these financings. This expectation also assumes that Oncor will perform in accordance with our expectations, and there can be no assurance that this will occur. In addition, we may encounter additional costs to manage our investment in Oncor, may fail to realize some or any of the benefits anticipated in the Merger, may be subject to currently unknown liabilities as a result of the Merger, or may be subject to other factors that affect preliminary estimates.

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.

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.

IEnova did not pay dividends to minority shareholders in the three months ended March 31, 2018 and paid $67 million in the year ended December 31, 2017.

Sempra Renewables

We expect Sempra Renewables to require funds for the development of and investment in electric renewable energy projects. Projects at Sempra Renewables may be financed through a combination of operating cash flow, project financing, funds from the parent, partnering in joint ventures, and other forms of equity sales, including tax equity. The varying costs and structure of these alternative financing sources impact the projects’ returns and their earnings profiles.

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Sempra LNG & Midstream

We expect Sempra LNG & Midstream to require funding for the development and expansion of its portfolio of projects, which may be financed through a combination of operating cash flow, funding from the parent, 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)
	Three months ended March 31, 2018		2018 change					Three months ended March 31, 2017
Sempra Energy Consolidated	$	966	$	(38	)	(4	)%	$	1,004
SDG&E	404		18			5		386
SoCalGas	419		(44		)	(10	)	463

Sempra Energy Consolidated

Cash provided by operating activities at Sempra Energy decreased in 2018 primarily due to:


▪	$34 million increase in accounts receivable in 2018 compared to a $94 million decrease in 2017;


▪	$62 million in purchases of GHG allowances in 2018 compared to $13 million in 2017 at the California Utilities;


▪	$30 million increase in seasonal liability related to temporary last-in-first-out (LIFO) liquidation at SoCalGas in 2017, primarily due to changes in natural gas inventory value;


▪	$26 million payment for marine concession fees for liquid fuels terminals; and


▪	$22 million decrease in inventory in 2018 compared to a $43 million decrease in 2017; offset by


▪	$83 million decrease in accounts payable in 2018 compared to a $137 million decrease in 2017;


▪	$29 million decrease in income taxes receivable in 2018 compared to a $23 million increase in 2017;


▪	$47 million higher net income, adjusted for noncash items included in earnings, in 2018 compared to 2017;


▪	$94 million increase in net overcollected regulatory balancing accounts (including long-term amounts included in regulatory assets) at SoCalGas in 2018 compared to a $51 million increase in 2017; and


▪	$59 million decrease in net undercollected regulatory balancing accounts (including long-term amounts included in regulatory assets) at SDG&E in 2018 compared to a $27 million decrease in 2017.

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SDG&E

Cash provided by operating activities at SDG&E increased in 2018 primarily due to:


▪	$59 million decrease in net undercollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2018 compared to a $27 million decrease in 2017; and


▪	$9 million decrease in NDT in 2018 as a result of CPUC authorization to withdraw trust funds for SONGS decommissioning costs incurred primarily in 2018; offset by


▪	$30 million in purchases of GHG allowances in 2018 compared to $2 million in 2017.

SoCalGas

Cash provided by operating activities at SoCalGas decreased in 2018 primarily due to:


▪	$6 million decrease in accounts receivable in 2018 compared to an $81 million decrease in 2017;


▪	$30 million increase in seasonal liability related to temporary LIFO liquidation in 2017, primarily due to changes in natural gas inventory value; and


▪	$32 million in purchases of GHG allowances in 2018 compared to $11 million in 2017; offset by


▪	$94 million increase in net overcollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2018 compared to a $51 million increase in 2017; and


▪	$24 million higher net income, adjusted for noncash items included in earnings, in 2018 compared to 2017.

CASH FLOWS FROM INVESTING ACTIVITIES



CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
	Three months ended March 31, 2018			2018 change				Three months ended March 31, 2017⁽¹⁾
Sempra Energy Consolidated	$	(10,632	)	$	9,606	936	%	$	(1,026	)
SDG&E	(475		)	95		25		(380		)
SoCalGas	(400		)	8		2		(392		)

⁽¹⁾ Reflects the adoption of 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:


▪	$9.55 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; and


▪	$43 million increase in capital expenditures.

SDG&E

Cash used in investing activities at SDG&E increased in 2018 primarily due to:


▪	$57 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:


▪	$46 million increase in capital expenditures; offset by


▪	$35 million increase in advances to Sempra Energy in 2017.

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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)
	Three months ended March 31,
	2018		2017
SDG&E:
Improvements to electric and natural gas distribution systems, including certain pipeline safety
and generation systems	$	350	$	308
PSEP	8		10
Improvements to electric transmission systems	114		92
Electric generation plants and equipment	3		8
SoCalGas:
Improvements to natural gas distribution, transmission and storage systems, and for certain
pipeline safety	357		307
PSEP	44		36
Advanced metering infrastructure	2		14
Sempra South American Utilities:
Improvements to electric transmission and distribution systems and generation projects in Peru	40		29
Improvements to electric transmission and distribution infrastructure in Chile	16		14
Sempra Mexico:
Construction of the Sonora, Ojinaga and San Isidro pipeline projects	18		85
Construction of other natural gas pipeline and renewables projects, and capital expenditures at Ecogas	41		9
Sempra Renewables:
Construction costs for wind projects	5		28
Construction costs for solar projects	26		41
Sempra LNG & Midstream:
Cameron Interstate Pipeline expansion and other LNG liquefaction development costs	5		3
Other	1		—
Parent and other	5		8
Total	$	1,035	$	992

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 $13.4 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 additional capital expenditures planned at Sempra Mexico.

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CASH FLOWS FROM FINANCING ACTIVITIES



CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
	Three months ended March 31, 2018			2018 change		Three months ended March 31, 2017
Sempra Energy Consolidated	$	9,608		$	9,654	$	(46	)
SDG&E	67			62		5
SoCalGas	(16		)	46		(62		)

Sempra Energy Consolidated

At Sempra Energy, financing activities were a source of cash in 2018 compared to a use of cash in 2017, primarily due to:


▪	$5.4 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:


◦	$4.9 billion for long-term debt ($5 billion in 2018 compared to $50 million in 2017), and


◦	$527 million for commercial paper and other short-term debt ($1 billion in 2018 compared to $492 million in 2017);


▪	$1.7 billion proceeds, net of $32 million in offering costs, from the issuance of mandatory convertible preferred stock in 2018;


▪	$1.3 billion proceeds, net of $24 million in offering costs, from issuances of common stock in 2018;


▪	$1.1 billion increase in short-term debt in 2018 compared to a $97 million decrease in 2017; and


▪	$120 million lower payments of debt with maturities greater than 90 days, including:


◦	$84 million for long-term debt ($105 million in 2018 compared to $189 million in 2017), and


◦	$36 million for commercial paper and other short-term debt ($88 million in 2018 compared to $124 million in 2017).

SDG&E

Cash provided by financing activities at SDG&E increased in 2018, primarily due to:


▪	$175 million common dividends paid in 2017; and


▪	$140 million lower payments of long-term debt in 2018; offset by


▪	$256 million lower increase in short-term debt borrowings in 2018.

SoCalGas

Cash used in financing activities at SoCalGas decreased in 2018 due to a lower decrease in short-term debt borrowings in 2018.

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 $7.3 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⁾	161		310		238		1,550		2,259
Total	$	161	$	1,310	$	938	$	4,850	$	7,259


⁽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 March 31, 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.

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CREDIT RATINGS

The credit ratings of Sempra Energy, SDG&E and SoCalGas remained at investment grade levels during the first three months of 2018. On April 11, 2018, Moody’s affirmed all SDG&E ratings and changed the rating outlook for SDG&E to negative from stable. SDG&E’s potential exposure created by the application of a strict liability standard in California and inverse condemnation risk led Moody’s to reassess the credit supportiveness of the regulatory environment in the state of California. Our credit ratings may affect the rates at which borrowings bear interest and the commitment fees on available unused credit. 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.

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. Shortly after the consummation of the Merger, Oncor’s credit ratings were upgraded by all three major rating agencies.

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” and “Item 1A. Risk Factors” contained in the Annual Report.

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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 EV charging.		$	50	§	In January 2018, received approval for six priority projects at $20 million.
					§	In March 2018, draft decision issued, 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 $169 million.
§	January 2018 application, pursuant to SB 350, to make investments to support medium-duty and high-duty EVs with an estimated implementation cost of $7 million of O&M.		$	226	§	Application pending; draft decision expected in the first quarter 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			§	Draft decision issued in April 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
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	§	Application pending; joint party settlement filed January 2018; draft decision expected in the second quarter of 2018.

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, at this point, we have been 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. The CPUC may grant a rehearing, modify its decision, or deny the request and affirm its original decision. We will appeal the decision with the California Courts of Appeal seeking to reverse the CPUC’s decision, if necessary. 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.

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


▪	Potential Impacts of Community Choice Aggregation and Direct Access


▪	Renewable Energy Procurement


▪	Clean Energy and Pollution Reduction Act – California SB 350


▪	SONGS

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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 third quarter of 2018.
§	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

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), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Cost Estimates and Accounting Impact

At March 31, 2018, SoCalGas estimates that its costs related to the Leak are $954 million, which includes $928 million of costs recovered or probable of recovery from insurance. Of the $954 million of estimated costs, approximately 60 percent is for the temporary relocation program (including cleaning costs and certain labor costs). Other estimated costs include amounts for efforts to control the well, stop the Leak, stop or reduce the emissions, and the estimated cost of the root cause analysis being conducted by an independent third party to investigate the cause of the Leak. The remaining portion of the $954 million includes legal costs incurred to defend litigation, the estimated costs to settle certain actions, 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. The $954 million represents management’s best estimate of these costs related to the Leak. Of these costs, a substantial portion has been paid and $122 million is accrued as Reserve for Aliso Canyon Costs as of March 31, 2018 on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets for amounts expected to be paid after March 31, 2018.

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Consolidated Balance Sheets. This amount is net of insurance retentions and $481 million of insurance proceeds we received through March 31, 2018 related to control-of-well expenses, lost gas and temporary relocation costs. If we were to conclude that this receivable or a portion of it was no longer probable of recovery from insurers, some or all of this receivable 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 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 above amounts 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 of $954 million does not include certain other costs expensed by Sempra Energy through March 31, 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 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.

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

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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.

CALIFORNIA UTILITIES – JOINT MATTERS

Capital Project Update

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
Pipeline Safety & Reliability Project
§	September 2015 application and March 2016 amended application seeking authority to recover the estimated $633 million cost of the project, involving construction of an approximately 47-mile, 36-inch natural gas transmission pipeline in San Diego County.		$	633	§	Procedural schedule set for two phases to address (1) long-term need and planning assumptions, and (2) costs, alternatives and environmental impacts.
					§	In May 2018, a draft decision was issued that denies the application, without prejudice, and instead directs SDG&E and SoCalGas to submit a hydrotest or replacement plan for the existing Line 1600 in its present corridor. If the draft decision is adopted, phase 2 will become moot.
§	Would implement pipeline safety requirements and modernize system; improve system reliability and resiliency by minimizing dependence on a single pipeline; and enhance operational flexibility to manage stress conditions by increasing system capacity.
					§	PSRP is a PSEP project. Our investment in PSRP, totaling approximately $35 million at SDG&E as of March 31, 2018, evaluated test or replace options for Line 1600 consistent with the PSEP decision tree previously approved by the CPUC. We expect a final decision on PSRP as early as the second quarter of 2018.
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	§	A CPUC OIR will incorporate the proposals sponsored by SDG&E and SoCalGas, and their pending applications filed in May 2017 will be dismissed without prejudice.
			to
			$	508
§	Estimated implementation cost of $2 million of O&M at SDG&E and $3 million to $4 million of O&M at SoCalGas.				§	September 2017 resolution approved extension of 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.

Natural Gas Pipeline Operations Safety Assessments

As we discuss in “Item 7. MD&A – Factors Influencing Future Performance” in the Annual Report, since 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 the PSRP, which we discuss in the table above. Both utilities have filed joint applications or plan to file future applications with the CPUC for review of the PSEP project costs as follows:

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PIPELINE SAFETY ENHANCEMENT PLAN – REASONABLENESS REVIEW SUMMARY
(Dollars in millions)
	2011 through March 31, 2018
	Total invested⁽¹⁾		CPUC review completed⁽²⁾		CPUC review pending⁽³⁾		2018 and future applications⁽⁴⁾⁽⁵⁾
Sempra Energy Consolidated:
Capital	$	1,544	$	8	$	144	$	1,392
Operation and maintenance	185		25		63		97
Total	$	1,729	$	33	$	207	$	1,489
SoCalGas:
Capital	$	1,189	$	8	$	130	$	1,051
Operation and maintenance	176		25		62		89
Total	$	1,365	$	33	$	192	$	1,140
SDG&E:
Capital	$	355	$	—	$	14	$	341
Operation and maintenance	9		—		1		8
Total	$	364	$	—	$	15	$	349


⁽¹⁾	Excludes disallowed costs through March 31, 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 $35 million of costs incurred for the PSRP.


⁽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 $12 million of pre-engineering costs incurred to support projects under development and submitted as part of the Forecast Application filed in March 2017. Both decisions are expected in 2018.


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


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

SEMPRA TEXAS UTILITY

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 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, upon consummation of the Merger, 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 Oncor and 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:


▪	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);

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


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


▪	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 regulatory commitments, governance mechanisms and restrictions, 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.

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.

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SEMPRA SOUTH AMERICAN UTILITIES

Regulated Rates

Chilquinta Energía’s most recent review process for transmission rates was completed in September 2017 and final approval is expected in the second quarter of 2018. Upon approval, the transmission rates will cover the period from January 2018 through December 2019, which we do not expect to have a material impact on our results.

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
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.
§	In April 2018, entered into two long-term contracts for the receipt, storage and delivery of hydrocarbons with Chevron Combustibles de México S. de R.L. de C.V. and another global oil company for 100 percent of the terminal’s storage capacity. Both contracts contain an option for the customer to acquire 20 percent of the equity of the terminal after commercial operations begin.

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. In 2015, Sempra LNG & Midstream and IEnova entered into a project development agreement with a subsidiary of PEMEX; however, PEMEX’s cost sharing obligations under that agreement ended on December 31, 2017. The development of this project is subject to numerous risks and uncertainties, including the receipt of a number of permits and regulatory approvals; finding suitable partners and customers; obtaining financing; negotiating and completing suitable commercial agreements, including joint venture agreements, LNG sales agreements, gas supply agreements and construction contracts; 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

Our TdM power plant is currently held for sale, as we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

SEMPRA RENEWABLES

Sempra Renewables’ 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.

Sempra Renewables’ future performance and 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.

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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.

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 Chicago Bridge & Iron Company N.V., 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 ENGIE S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd. The terms of these agreements are concurrent with the liquefaction and regasification tolling capacity agreements.

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. In October 2016, the EPC contractor indicated that the Cameron LNG project would not achieve its originally scheduled dates for completion and subsequently provided project schedules reflecting further delays to the Cameron LNG project.

During the course of construction of large projects like Cameron LNG, contractors often assert that they are owed additional compensation, schedule extensions, or both. 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

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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 and 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 increase 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.

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. One of the partners has announced that it intends to transfer its interest in the Cameron LNG JV to TOTAL S.A., and we expect that discussions on the potential expansion will continue after TOTAL S.A. becomes a member of the Cameron LNG JV. There can be no assurance that a mutually agreeable expansion structure will be agreed upon 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 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 production capability of approximately 13.5 Mtpa, or 698 Bcf per year;


▪	three LNG storage tanks;


▪	natural gas liquids and refrigerant storage;


▪	feed gas pre-treatment facilities; and


▪	two berths and associated marine and loading facilities.

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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. The agreement specifies how the parties will share costs, and establishes a framework for the parties to work jointly on permitting, design, engineering, commercial and marketing activities associated with developing the Port Arthur LNG liquefaction project.

Development of the Port Arthur LNG liquefaction project is subject to a number of risks and uncertainties, including obtaining customer commitments, completing the required commercial agreements, such as joint venture agreements, LNG sales agreements and gas supply agreements; completing construction contracts; securing all necessary permits and approvals; obtaining financing and incentives; reaching a final investment decision; and other factors associated with the potential investment. See “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

The future performance of our natural gas storage assets could be impacted by ongoing changes in the U.S. natural gas market, which could lead to sustained diminished natural gas storage values.

The recorded value of our long-lived natural gas storage assets at March 31, 2018 is $1.4 billion. Historically, the value of natural gas storage services has positively correlated with the difference between the seasonal prices of natural gas, among other factors. In general, over the past several years, seasonal differences in natural gas prices have declined, which have contributed to lower prices for storage services. As our legacy (higher rate) sales contracts mature at our Bay Gas and Mississippi Hub facilities, replacement sales contract rates have been and could continue to be lower than has historically been the case. Lower sales revenues may not be offset by cost reductions, which could lead to depressed asset values. Future investment in Bay Gas, Mississippi Hub and LA Storage will be dependent on market demand and estimates of long-term storage values. Our LA Storage development project construction permit expired in June 2017 and future development will require approval of a new construction permit by the FERC. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage pipeline, that is not currently contracted.

We perform recovery testing of our recorded asset values when market conditions indicate that such values may not be recoverable. In the event such values are not recoverable, we would consider the fair value of these assets relative to their carrying value. To the extent the carrying value is in excess of the fair value, we would record a noncash impairment charge. A significant impairment charge related to our natural gas storage assets would have a material adverse effect on our results of operations in the period in which it is recorded.

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 Note 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)
	March 31, 2018						December 31, 2017
	Sempra Energy Consolidated		SDG&E		SoCalGas		Sempra Energy Consolidated		SDG&E		SoCalGas
California Utilities fixed-rate	$	7,565	$	4,556	$	3,009	$	7,582	$	4,573	$	3,009
California Utilities variable-rate	292		292		—		295		295		—
Other fixed-rate	11,559		—		—		7,735		—		—
Other variable-rate	2,660		—		—		1,539		—		—


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

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 10 percent on all of Sempra Energy’s effective variable-rate, long-term debt at March 31, 2018, the change in earnings over the next 12-month period ended March 31, 2019 would be $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 March 31, 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 March 31, 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.

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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,” as well as the risk factors disclosed in “Item 1A. Risk Factors” in the Annual Report. 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, 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.

ITEM 6. EXHIBITS

The following exhibits relate to each registrant as indicated.



EXHIBIT 10 -- MATERIAL CONTRACTS

Sempra Energy
10.1		Confirmation of Registered Forward Transaction, dated January 4, 2018, by and between Sempra Energy and Morgan Stanley & Co. LLC (Form 8-K filed on January 9, 2018, Exhibit 1.3).

10.2		Confirmation of Registered Forward Transaction, dated January 4, 2018, by and between Sempra Energy and Royal Bank of Canada (Form 8-K filed on January 9, 2018, Exhibit 1.4).

10.3		Confirmation of Registered Forward Transaction, dated January 4, 2018, by and between Sempra Energy and Barclays Bank PLC (Form 8-K filed on January 9, 2018, Exhibit 1.5).

10.4		Amendment to Confirmation of Registered Forward Transaction, dated February 27, 2018, by and between Sempra Energy and Morgan Stanley & Co. LLC.

10.5		Amendment to Confirmation of Registered Forward Transaction, dated February 27, 2018, by and between Sempra Energy and Royal Bank of Canada.

10.6		Amendment to Confirmation of Registered Forward Transaction, dated February 27, 2018, by and between Sempra Energy and Barclays Bank PLC.




10.7		Sempra Energy Annual Incentive Plan.

Sempra Energy/San Diego Gas & Electric/Southern California Gas Company

Compensation
10.8		Form of Sempra Energy 2013 Long-Term Incentive Plan 2018 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure - S&P 500 Index.

10.9		Form of Sempra Energy 2013 Long-Term Incentive Plan 2018 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure - S&P 500 Utilities Index.

10.10		Form of Sempra Energy 2013 Long-Term Incentive Plan 2018 Performance-Based Restricted Stock Unit Award - EPS Growth Performance Measure.

10.11		Form of Sempra Energy 2013 Long-Term Incentive Plan 2018 Time-Based Restricted Stock Unit Award - Cliff vest.

10.12		Form of Sempra Energy 2013 Long-Term Incentive Plan 2018 Special Time-Based Restricted Stock Unit Award - Two-year vest.

10.13		Form of Sempra Energy 2013 Long-Term Incentive Plan 2018 Special Time-Based Restricted Stock Unit Award - Multi-year vest.

EXHIBIT 12 -- STATEMENTS RE: COMPUTATION OF RATIOS

Sempra Energy
12.1		Sempra Energy Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.

San Diego Gas & Electric Company
12.2		San Diego Gas & Electric Company Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.

Southern California Gas Company
12.3		Southern California Gas Company Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.

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.

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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.

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: May 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: May 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: May 7, 2018	By: /s/ Bruce A. Folkmann
	Bruce A. Folkmann Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

128