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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

FORM 10-Q


(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended		September 30, 2016


	or


[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from			to


Commission File No.		Exact Name of Registrants as Specified in their Charters, Address and Telephone Number	States 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 registrant has submitted electronically and posted on its corporate Web site, 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 registrant was required to submit and post such files).

Sempra Energy				Yes	X	No
San Diego Gas & Electric Company				Yes	X	No
Southern California Gas Company				Yes	X	No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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 October 27, 2016:

Sempra Energy		250,060,973 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		4

PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	89
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	134
Item 4.	Controls and Procedures	135

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	136
Item 1A.	Risk Factors	136
Item 6.	Exhibits	136

Signatures		139

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.

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 necessarily based upon assumptions with respect to the future, involve risks and uncertainties, and are not guarantees of performance. 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,” “intends,” “assumes,” “depends,” “should,” “could,” “would,” “will,” “confident,” “may,” “potential,” “possible,” “proposed,” “target,” “pursue,” “goals,” “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 forward-looking statements include


▪	local, regional, national and international economic, competitive, political, legislative, legal and regulatory conditions, decisions and developments;

▪

actions and the timing of actions, including general rate case decisions, new regulations, issuances of permits to construct, operate, and maintain facilities and equipment and to use land, franchise agreements and licenses for operation, by the California Public Utilities Commission, California State Legislature, U.S. Department of Energy, California Division of Oil, Gas, and Geothermal Resources, Federal Energy Regulatory Commission, Nuclear Regulatory Commission, California Energy Commission, U.S. Environmental Protection Agency, Pipeline and Hazardous Materials Safety Administration, California Air Resources Board, South Coast Air Quality Management District, Los Angeles County Department of Public Health, Mexican Competition Commission, states, cities and counties, and other regulatory and governmental bodies in the countries in which we operate;


▪	the timing and success of business development efforts and construction, maintenance and capital projects, including risks in obtaining, maintaining or extending permits, licenses, certificates and other authorizations on a timely basis, risks in obtaining the consent of our partners, and risks in obtaining adequate and competitive financing for such projects;


▪	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, and delays in, or disallowance or denial of, regulatory agency authorization to recover costs in rates from customers or regulatory agency approval for projects required to enhance safety and reliability;


▪	the availability of electric power, natural gas and liquefied natural gas, and natural gas pipeline and storage capacity, including disruptions caused by failures in the North American transmission grid, moratoriums on the ability to withdraw natural gas from or inject natural gas into storage facilities, pipeline explosions and equipment failures;

▪

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


▪	risks posed by decisions and actions of third parties who control the operations of investments in which we do not have a controlling interest, and risks that our partners or counterparties will be unable (due to liquidity issues, bankruptcy or otherwise) or unwilling to fulfill their contractual commitments;

▪

weather conditions, natural disasters, catastrophic accidents, equipment failures, terrorist attacks and other events that may disrupt our operations, damage our facilities and systems, cause the release of greenhouse gases, radioactive materials and harmful emissions, and subject us to third-party liability for property damage or personal injuries, fines and penalties, some of which may not be covered by insurance (including costs in excess of applicable policy limits) or may be disputed by insurers;


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


▪	the ability to win competitively bid infrastructure projects against a number of strong competitors willing to aggressively bid for these projects;


▪	capital markets conditions, including the availability of credit and the liquidity of our investments, and inflation, interest and currency exchange rates;


▪	disallowance of regulatory assets associated with, or decommissioning costs of, the San Onofre Nuclear Generating Station facility due to increased regulatory oversight, including motions to modify settlements;


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


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


▪	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;


▪	the impact on customer rates and other adverse consequences due to possible departing retail load resulting from customers transferring to Direct Access and Community Choice Aggregation;


▪	the inability or determination not to enter into long-term supply and sales agreements or long-term firm capacity agreements due to insufficient market interest, unattractive pricing or other factors; and


▪	other uncertainties, all of which are difficult to predict and many of which 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 and in our most recent Annual Report on Form 10-K and other reports that we file with the Securities and Exchange Commission.

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts)
	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(unaudited)
REVENUES
Utilities	$	2,264		$	2,213		$	6,700		$	6,768
Energy-related businesses	271			268			613			762
Total revenues	2,535			2,481			7,313			7,530
EXPENSES AND OTHER INCOME
Utilities:
Cost of natural gas	(208		)	(201		)	(702		)	(786		)
Cost of electric fuel and purchased power	(604		)	(666		)	(1,680		)	(1,645		)
Energy-related businesses:
Cost of natural gas, electric fuel and purchased power	(95		)	(91		)	(213		)	(262		)
Other cost of sales	(32		)	(34		)	(293		)	(111		)
Operation and maintenance	(703		)	(701		)	(2,109		)	(2,072		)
Depreciation and amortization	(328		)	(315		)	(970		)	(925		)
Franchise fees and other taxes	(108		)	(111		)	(315		)	(314		)
Impairment losses	(132		)	—			(154		)	—
Plant closure adjustment	—			—			—			21
Gain on sale of assets	131			—			131			62
Equity earnings, before income tax	12			33			4			79
Remeasurement of equity method investment	617			—			617			—
Other income, net	26			12			98			88
Interest income	7			6			19			23
Interest expense	(136		)	(143		)	(421		)	(416		)
Income before income taxes and equity earnings of certain unconsolidated subsidiaries	982			270			1,325			1,272
Income tax expense	(282		)	(15		)	(284		)	(276		)
Equity earnings, net of income tax	19			27			69			64
Net income	719			282			1,110			1,060
Earnings attributable to noncontrolling interests	(97		)	(34		)	(118		)	(79		)
Preferred dividends of subsidiary	—			—			(1		)	(1		)
Earnings	$	622		$	248		$	991		$	980


Basic earnings per common share	$	2.48		$	1.00		$	3.96		$	3.95
Weighted-average number of shares outstanding, basic (thousands)	250,386			248,432			250,073			248,090

Diluted earnings per common share	$	2.46		$	0.99		$	3.93		$	3.91
Weighted-average number of shares outstanding, diluted (thousands)	252,405			251,024			251,976			250,665

Dividends declared per share of common stock	$	0.76		$	0.70		$	2.27		$	2.10

See Notes to Condensed Consolidated Financial Statements.



SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Sempra Energy shareholders’ equity
	Pretax amount			Income tax (expense) benefit			Net-of-tax amount			Noncontrolling interests (after-tax)			Total
	Three months ended September 30, 2016 and 2015
	(unaudited)
2016:
Net income	$	904		$	(282	)	$	622		$	97		$	719
Other comprehensive income (loss):
Foreign currency translation adjustments	(28		)	—			(28		)	(7		)	(35		)
Financial instruments	23			(10		)	13			5			18
Pension and other postretirement benefits	4			(2		)	2			—			2
Total other comprehensive loss	(1		)	(12		)	(13		)	(2		)	(15		)
Comprehensive income	$	903		$	(294	)	$	609		$	95		$	704
2015:
Net income	$	263		$	(15	)	$	248		$	34		$	282
Other comprehensive income (loss):
Foreign currency translation adjustments	(92		)	—			(92		)	(8		)	(100		)
Financial instruments	(128		)	50			(78		)	(3		)	(81		)
Pension and other postretirement benefits	7			(2		)	5			—			5
Total other comprehensive loss	(213		)	48			(165		)	(11		)	(176		)
Comprehensive income	$	50		$	33		$	83		$	23		$	106



	Nine months ended September 30, 2016 and 2015
	(unaudited)
2016:
Net income	$	1,276		$	(284	)	$	992		$	118		$	1,110
Other comprehensive income (loss):
Foreign currency translation adjustments	51			—			51			(2		)	49
Financial instruments	(214		)	100			(114		)	1			(113		)
Pension and other postretirement benefits	8			(4		)	4			—			4
Total other comprehensive loss	(155		)	96			(59		)	(1		)	(60		)
Comprehensive income	1,121			(188		)	933			117			1,050
Preferred dividends of subsidiary	(1		)	—			(1		)	—			(1		)
Comprehensive income, after preferred
dividends of subsidiary	$	1,120		$	(188	)	$	932		$	117		$	1,049
2015:
Net income	$	1,257		$	(276	)	$	981		$	79		$	1,060
Other comprehensive income (loss):
Foreign currency translation adjustments	(197		)	—			(197		)	(21		)	(218		)
Financial instruments	(122		)	48			(74		)	(2		)	(76		)
Pension and other postretirement benefits	11			(4		)	7			—			7
Total other comprehensive loss	(308		)	44			(264		)	(23		)	(287		)
Comprehensive income	949			(232		)	717			56			773
Preferred dividends of subsidiary	(1		)	—			(1		)	—			(1		)
Comprehensive income, after preferred
dividends of subsidiary	$	948		$	(232	)	$	716		$	56		$	772

See Notes to Condensed Consolidated Financial Statements.



SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	September 30, 2016			December 31, 2015(1)
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	518		$	403
Restricted cash	14			27
Accounts receivable – trade, net	1,062			1,283
Accounts receivable – other	171			190
Due from unconsolidated affiliates	8			6
Income taxes receivable	28			30
Inventories	302			298
Regulatory balancing accounts – undercollected	248			307
Fixed-price contracts and other derivatives	53			80
Assets held for sale	181			—
Other	339			267
Total current assets	2,924			2,891

Other assets:
Restricted cash	12			20
Due from unconsolidated affiliates	195			186
Regulatory assets	3,424			3,273
Nuclear decommissioning trusts	1,068			1,063
Investments	1,840			2,905
Goodwill	2,150			819
Other intangible assets	397			404
Dedicated assets in support of certain benefit plans	439			464
Insurance receivable for Aliso Canyon costs	664			325
Deferred income taxes	211			120
Sundry	715			641
Total other assets	11,115			10,220

Property, plant and equipment:
Property, plant and equipment	41,938			38,200
Less accumulated depreciation and amortization	(10,451		)	(10,161		)
Property, plant and equipment, net ($365 and $383 at September 30, 2016 and December 31, 2015, respectively, related to VIE)	31,487			28,039
Total assets	$	45,526		$	41,150


(1)	Derived from audited financial statements.

See Notes to Condensed Consolidated Financial Statements.



SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	September 30, 2016			December 31, 2015(1)
	(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$	2,869		$	622
Accounts payable – trade	1,173			1,133
Accounts payable – other	125			142
Due to unconsolidated affiliates	9			14
Dividends and interest payable	357			303
Accrued compensation and benefits	298			423
Regulatory balancing accounts – overcollected	146			34
Current portion of long-term debt	904			907
Fixed-price contracts and other derivatives	94			56
Customer deposits	153			153
Reserve for Aliso Canyon costs	73			274
Liabilities held for sale	35			—
Other	558			551
Total current liabilities	6,794			4,612

Long-term debt ($296 and $303 at September 30, 2016 and December 31, 2015, respectively, related to VIE)	13,522			13,134

Deferred credits and other liabilities:
Customer advances for construction	153			149
Pension and other postretirement benefit plan obligations, net of plan assets	1,199			1,152
Deferred income taxes	3,326			3,157
Deferred investment tax credits	34			32
Regulatory liabilities arising from removal obligations	2,878			2,793
Asset retirement obligations	2,508			2,126
Fixed-price contracts and other derivatives	413			240
Deferred credits and other	1,508			1,176
Total deferred credits and other liabilities	12,019			10,825

Commitments and contingencies (Note 11)

Equity:
Preferred stock (50 million shares authorized; none issued)	—			—
Common stock (750 million shares authorized; 250 million and 248 million shares outstanding at September 30, 2016 and December 31, 2015, respectively; no par value)	2,684			2,621
Retained earnings	10,527			9,994
Accumulated other comprehensive income (loss)	(865		)	(806		)
Total Sempra Energy shareholders’ equity	12,346			11,809
Preferred stock of subsidiary	20			20
Other noncontrolling interests	825			750
Total equity	13,191			12,579
Total liabilities and equity	$	45,526		$	41,150


(1)	Derived from audited financial statements.

See Notes to Condensed Consolidated Financial Statements.



SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Nine months ended September 30,
	2016			2015
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,110		$	1,060
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	970			925
Deferred income taxes and investment tax credits	170			179
Impairment losses	154			—
Plant closure adjustment	—			(21		)
Gain on sale of assets	(131		)	(62		)
Equity earnings	(73		)	(143		)
Remeasurement of equity method investment	(617		)	—
Fixed-price contracts and other derivatives	39			(20		)
Other	50			28
Net change in other working capital components	224			260
Insurance receivable for Aliso Canyon costs	(339		)	—
Changes in other assets	(4		)	(112		)
Changes in other liabilities	138			(5		)
Net cash provided by operating activities	1,691			2,089

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(3,087		)	(2,227		)
Expenditures for investments and acquisition of businesses, net of cash and cash equivalents acquired	(1,212		)	(183		)
Proceeds from sale of assets, net of cash sold	761			347
Distributions from investments	23			14
Purchases of nuclear decommissioning and other trust assets	(418		)	(407		)
Proceeds from sales by nuclear decommissioning and other trusts	486			431
Increases in restricted cash	(53		)	(81		)
Decreases in restricted cash	71			68
Advances to unconsolidated affiliates	(12		)	(24		)
Repayments of advances to unconsolidated affiliates	11			74
Other	(2		)	9
Net cash used in investing activities	(3,432		)	(1,979		)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	(510		)	(468		)
Preferred dividends paid by subsidiary	(1		)	(1		)
Issuances of common stock	40			41
Repurchases of common stock	(55		)	(74		)
Issuances of debt (maturities greater than 90 days)	2,013			2,058
Payments on debt (maturities greater than 90 days)	(1,298		)	(1,316		)
Increase (decrease) in short-term debt, net	1,636			(201		)
Deposit for sale of noncontrolling interest	78			—
Net distributions to noncontrolling interests	(43		)	(57		)
Tax benefit related to share-based compensation	—			56
Other	(12		)	(9		)
Net cash provided by financing activities	1,848			29

Effect of exchange rate changes on cash and cash equivalents	8			(12		)

Increase in cash and cash equivalents	115			127
Cash and cash equivalents, January 1	403			570
Cash and cash equivalents, September 30	$	518		$	697

See Notes to Condensed Consolidated Financial Statements.



SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
	Nine months ended September 30,
	2016			2015
	(unaudited)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	367		$	355
Income tax payments, net of refunds	103			37

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Acquisition of businesses:
Assets acquired, net of cash and cash equivalents	$	2,692		$	10
Fair value of equity method investment immediately prior to acquisition	(1,144		)	—
Liabilities assumed	(448		)	(2		)
Accrued purchase price	(4		)	(5		)
Cash paid, net of cash and cash equivalents acquired	$	1,096		$	3

Accrued capital expenditures	$	483		$	459
Financing of build-to-suit property	—			61
Redemption of industrial development bonds	—			79
Common dividends issued in stock	40			41
Dividends declared but not paid	195			179

See Notes to Condensed Consolidated Financial Statements.



SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(unaudited)
Operating revenues
Electric	$	1,111		$	1,140		$	2,851		$	2,819
Natural gas	98			90			341			349
Total operating revenues	1,209			1,230			3,192			3,168
Operating expenses
Cost of electric fuel and purchased power	364			427			926			906
Cost of natural gas	25			27			89			112
Operation and maintenance	268			251			780			723
Depreciation and amortization	161			152			478			446
Franchise fees and other taxes	68			73			190			193
Plant closure adjustment	—			—			—			(21		)
Total operating expenses	886			930			2,463			2,359
Operating income	323			300			729			809
Other income, net	11			8			38			26
Interest expense	(49		)	(51		)	(145		)	(155		)
Income before income taxes	285			257			622			680
Income tax expense	(91		)	(75		)	(204		)	(217		)
Net income	194			182			418			463
(Earnings) losses attributable to noncontrolling interest	(11		)	(12		)	1			(20		)
Earnings attributable to common shares	$	183		$	170		$	419		$	443

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 September 30, 2016 and 2015
	(unaudited)
2016:
Net income	$	274	$	(91	)	$	183	$	11		$	194
Other comprehensive income (loss):
Financial instruments	—		—			—		5			5
Total other comprehensive income	—		—			—		5			5
Comprehensive income	$	274	$	(91	)	$	183	$	16		$	199
2015:
Net income	$	245	$	(75	)	$	170	$	12		$	182
Other comprehensive income (loss):
Financial instruments	—		—			—		(1		)	(1		)
Total other comprehensive loss	—		—			—		(1		)	(1		)
Comprehensive income	$	245	$	(75	)	$	170	$	11		$	181



	Nine months ended September 30, 2016 and 2015
	(unaudited)
2016:
Net income (loss)	$	623	$	(204	)	$	419	$	(1	)	$	418
Other comprehensive income (loss):
Financial instruments	—		—			—		4			4
Total other comprehensive income	—		—			—		4			4
Comprehensive income	$	623	$	(204	)	$	419	$	3		$	422
2015:
Net income/Comprehensive income	$	660	$	(217	)	$	443	$	20		$	463

See Notes to Condensed Consolidated Financial Statements.



SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	September 30, 2016			December 31, 2015(1)
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	23		$	20
Restricted cash	10			23
Accounts receivable – trade, net	358			331
Accounts receivable – other	17			17
Due from unconsolidated affiliates	88			1
Income taxes receivable	84			1
Inventories	73			75
Regulatory balancing accounts – net undercollected	248			307
Regulatory assets	124			107
Fixed-price contracts and other derivatives	23			53
Other	98			69
Total current assets	1,146			1,004

Other assets:
Deferred taxes recoverable in rates	971			914
Other regulatory assets	1,036			977
Nuclear decommissioning trusts	1,068			1,063
Sundry	373			301
Total other assets	3,448			3,255

Property, plant and equipment:
Property, plant and equipment	17,344			16,458
Less accumulated depreciation and amortization	(4,492		)	(4,202		)
Property, plant and equipment, net ($365 and $383 at September 30, 2016 and December 31, 2015, respectively, related to VIE)	12,852			12,256
Total assets	$	17,446		$	16,515


(1)	Derived from audited financial statements.

See Notes to Condensed Consolidated Financial Statements.



SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	September 30, 2016			December 31, 2015(1)
	(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$	54		$	168
Accounts payable	422			377
Due to unconsolidated affiliates	10			55
Interest payable	47			39
Accrued compensation and benefits	87			129
Accrued franchise fees	39			66
Current portion of long-term debt	191			50
Asset retirement obligations	72			99
Fixed-price contracts and other derivatives	59			51
Customer deposits	71			72
Other	116			101
Total current liabilities	1,168			1,207

Long-term debt ($296 and $303 at September 30, 2016 and December 31, 2015, respectively, related to VIE)	4,660			4,455

Deferred credits and other liabilities:
Customer advances for construction	53			46
Pension and other postretirement benefit plan obligations, net of plan assets	226			212
Deferred income taxes	2,628			2,472
Deferred investment tax credits	21			19
Regulatory liabilities arising from removal obligations	1,742			1,629
Asset retirement obligations	760			729
Fixed-price contracts and other derivatives	207			106
Deferred credits and other	441			364
Total deferred credits and other liabilities	6,078			5,577

Commitments and contingencies (Note 11)

Equity:
Common stock (255 million shares authorized; 117 million shares outstanding; no par value)	1,338			1,338
Retained earnings	4,160			3,893
Accumulated other comprehensive income (loss)	(8		)	(8		)
Total SDG&E shareholder’s equity	5,490			5,223
Noncontrolling interest	50			53
Total equity	5,540			5,276
Total liabilities and equity	$	17,446		$	16,515


(1)	Derived from audited financial statements.

See Notes to Condensed Consolidated Financial Statements.



SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Nine months ended September 30,
	2016			2015
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	418		$	463
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	478			446
Deferred income taxes and investment tax credits	98			170
Plant closure adjustment	—			(21		)
Fixed-price contracts and other derivatives	(2		)	(3		)
Other	(29		)	(14		)
Net change in other working capital components	14			136
Changes in other assets	(47		)	(93		)
Changes in other liabilities	3			10
Net cash provided by operating activities	933			1,094

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(959		)	(835		)
Purchases of nuclear decommissioning trust assets	(415		)	(404		)
Proceeds from sales by nuclear decommissioning trusts	486			431
Increases in restricted cash	(30		)	(29		)
Decreases in restricted cash	43			27
Increase in loans to affiliate, net	(107		)	—
Net cash used in investing activities	(982		)	(810		)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	(175		)	(150		)
Issuances of debt (maturities greater than 90 days)	498			388
Payments on debt (maturities greater than 90 days)	(148		)	(294		)
Decrease in short-term debt, net	(114		)	(202		)
Capital distributions made by VIE	(6		)	(14		)
Other	(3		)	—
Net cash provided by (used in) financing activities	52			(272		)

Increase in cash and cash equivalents	3			12
Cash and cash equivalents, January 1	20			8
Cash and cash equivalents, September 30	$	23		$	20

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	132		$	141
Income tax payments, net	165			62

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY
Accrued capital expenditures	$	139		$	142

See Notes to Condensed Consolidated Financial Statements.



SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
	(unaudited)

Operating revenues	$	686		$	620		$	2,336		$	2,448
Operating expenses
Cost of natural gas	171			163			571			626
Operation and maintenance	322			325			966			985
Depreciation and amortization	121			116			355			342
Franchise fees and other taxes	33			29			100			94
Impairment losses	1			—			23			—
Total operating expenses	648			633			2,015			2,047
Operating income (loss)	38			(13		)	321			401
Other income, net	8			8			24			25
Interest income	—			—			—			3
Interest expense	(25		)	(23		)	(71		)	(61		)
Income (loss) before income taxes	21			(28		)	274			368
Income tax (expense) benefit	(21		)	20			(75		)	(91		)
Net (loss) income	—			(8		)	199			277
Preferred dividend requirements	—			—			(1		)	(1		)
(Losses) earnings attributable to common shares	$	—		$	(8	)	$	198		$	276

See Notes to Condensed Financial Statements.



SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Pretax amount			Income tax (expense) benefit			Net-of-tax amount
	Three months ended September 30, 2016 and 2015
	(unaudited)
2016:
Net income	$	21		$	(21	)	$	—
Other comprehensive income (loss):
Financial instruments	1			—			1
Total other comprehensive income	1			—			1
Comprehensive income	$	22		$	(21	)	$	1
2015:
Net loss/Comprehensive loss	$	(28	)	$	20		$	(8	)



	Nine months ended September 30, 2016 and 2015
	(unaudited)
2016:
Net income	$	274	$	(75	)	$	199
Other comprehensive income (loss):
Financial instruments	1		—			1
Total other comprehensive income	1		—			1
Comprehensive income	$	275	$	(75	)	$	200
2015:
Net income/Comprehensive income	$	368	$	(91	)	$	277

See Notes to Condensed Financial Statements.



SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED BALANCE SHEETS
(Dollars in millions)
	September 30, 2016			December 31, 2015(1)
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	8		$	58
Accounts receivable – trade, net	344			635
Accounts receivable – other	81			99
Due from unconsolidated affiliates	35			48
Income taxes receivable	12			—
Inventories	77			79
Regulatory assets	8			7
Other	70			40
Total current assets	635			966

Other assets:
Regulatory assets arising from pension obligations	747			699
Other regulatory assets	637			636
Insurance receivable for Aliso Canyon costs	664			325
Sundry	276			207
Total other assets	2,324			1,867

Property, plant and equipment:
Property, plant and equipment	15,186			14,171
Less accumulated depreciation and amortization	(4,997		)	(4,900		)
Property, plant and equipment, net	10,189			9,271
Total assets	$	13,148		$	12,104


(1)	Derived from audited financial statements.

See Notes to Condensed Financial Statements.



SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	September 30, 2016			December 31, 2015(1)
	(unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable – trade	$	330		$	422
Accounts payable – other	72			76
Income taxes payable	—			3
Accrued compensation and benefits	119			160
Regulatory balancing accounts – net overcollected	146			34
Current portion of long-term debt	1			9
Customer deposits	76			76
Reserve for Aliso Canyon costs	73			274
Other	182			184
Total current liabilities	999			1,238

Long-term debt	2,982			2,481

Deferred credits and other liabilities:
Customer advances for construction	101			103
Pension obligation, net of plan assets	765			716
Deferred income taxes	1,643			1,532
Deferred investment tax credits	12			14
Regulatory liabilities arising from removal obligations	1,136			1,145
Asset retirement obligations	1,714			1,354
Deferred credits and other	433			372
Total deferred credits and other liabilities	5,804			5,236

Commitments and contingencies (Note 11)

Shareholders’ equity:
Preferred stock	22			22
Common stock (100 million shares authorized; 91 million shares outstanding;
no par value)	866			866
Retained earnings	2,493			2,280
Accumulated other comprehensive income (loss)	(18		)	(19		)
Total shareholders’ equity	3,363			3,149
Total liabilities and shareholders’ equity	$	13,148		$	12,104


(1)	Derived from audited financial statements.

See Notes to Condensed Financial Statements.



SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Nine months ended September 30,
	2016			2015
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	199		$	277
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	355			342
Deferred income taxes and investment tax credits	52			98
Impairment losses	23			—
Other	(22		)	(18		)
Net change in other working capital components	135			48
Insurance receivable for Aliso Canyon costs	(339		)	—
Changes in other assets	2			(57		)
Changes in other liabilities	4			—
Net cash provided by operating activities	409			690

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(949		)	(946		)
Increase in loans to affiliate, net	(1		)	(250		)
Net cash used in investing activities	(950		)	(1,196		)

CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends paid	(1		)	(1		)
Issuances of long-term debt	499			599
Payments on long-term debt	(3		)	—
Decrease in short-term debt, net	—			(50		)
Other	(4		)	(4		)
Net cash provided by financing activities	491			544

(Decrease) increase in cash and cash equivalents	(50		)	38
Cash and cash equivalents, January 1	58			85
Cash and cash equivalents, September 30	$	8		$	123

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	60		$	53
Income tax payments, net	35			11

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued capital expenditures	$	150		$	172
Dividends declared but not paid	—			50

See Notes to Condensed Financial Statements.

SEMPRA ENERGY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. GENERAL

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 variable interest entities (VIEs). Sempra Energy’s principal operating units are


▪	San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), which are separate, reportable segments;


▪	Sempra International, which includes our Sempra South American Utilities and Sempra Mexico reportable segments; and


▪	Sempra U.S. Gas & Power, which includes our Sempra Renewables and Sempra Natural Gas reportable segments.

We provide descriptions of each of our segments in Note 12.

We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include the utilities in our Sempra International and Sempra U.S. Gas & Power operating units. As we discuss below and in Note 3, Sempra U.S. Gas & Power sold its natural gas distribution utilities in September 2016. Sempra Global is the holding company for most of our subsidiaries that are not subject to California utility regulation. All references in these Notes to “Sempra International,” “Sempra U.S. Gas & Power” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name.

Our Sempra Mexico segment includes the operating companies of our subsidiary, Infraestructura Energética Nova, S.A.B. de C.V. (IEnova), as well as certain holding companies and risk management activity. We discuss IEnova further in Note 1 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2015 (the Annual Report), which includes the combined reports for Sempra Energy, SDG&E and SoCalGas.

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. We discuss our investments in unconsolidated entities in Notes 3 and 4 herein and in Notes 3, 4 and 10 of the Notes to Consolidated Financial Statements in the Annual Report.

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 in Note 5 under “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 accounting principles generally accepted in the United States of America (U.S. GAAP) and in accordance with the interim-period-reporting requirements of Form 10-Q. Results of operations for interim periods are not necessarily indicative of results for the entire year. We evaluated events and transactions that occurred after September 30, 2016 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, 2015 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2015 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 Securities and Exchange Commission.

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.

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

Regulated Operations

Sempra South American Utilities has controlling interests in two electric distribution utilities in South America, Chilquinta Energía S.A. (Chilquinta Energía) in Chile and Luz del Sur S.A.A. (Luz del Sur) in Peru, and their subsidiaries. Sempra Mexico owns Ecogas México, S. de R.L. de C.V. (Ecogas), a natural gas distribution utility in northern Mexico. The California Utilities and Ecogas prepare their financial statements in accordance with U.S. GAAP provisions governing rate-regulated operations, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. Sempra Natural Gas owned Mobile Gas Service Corporation (Mobile Gas) in southwest Alabama and Willmut Gas Company (Willmut Gas) in Mississippi until they were sold in September 2016, as we discuss in Note 3. Mobile Gas and Willmut Gas also prepared their financial statements in accordance with U.S. GAAP provisions governing rate-regulated operations.

Certain business activities at IEnova are regulated by the Comisión Reguladora de Energía (or CRE, the Energy Regulatory Commission) and meet the regulatory accounting requirements of U.S. GAAP. Pipeline projects currently under construction by IEnova that meet the regulatory accounting requirements of U.S. GAAP record the impact of allowance for funds used during construction (AFUDC) related to equity. We discuss AFUDC in Note 5 below and in Note 1 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 statements. We do not discuss recent pronouncements that are not anticipated to have an impact on or are unrelated to our financial condition, results of operations, cash flows or disclosures.

SEMPRA ENERGY, SDG&E AND SOCALGAS

Accounting Standards Update (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 provides 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.

ASU 2015-14 defers the effective date of ASU 2014-09 by one year for all entities and permits early adoption on a limited basis. For public entities, ASU 2014-09 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted for fiscal years beginning after December 15, 2016, and is effective for interim periods in the year of adoption. We plan to adopt ASU 2014-09 on January 1, 2018 and are currently evaluating the transition method and the effect on our ongoing financial reporting. As part of our

evaluation, we continue to actively monitor outstanding issues currently being addressed by the American Institute of Certified Public Accountants’ Revenue Recognition Working Group and the Financial Accounting Standards Board’s Transition Resource Group, since conclusions reached by these groups may impact our application of these ASU’s.

ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities”: In addition to the presentation and disclosure requirements for financial instruments, ASU 2016-01 requires entities to measure equity investments not 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, 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. Upon adoption, 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. The guidance on equity securities without readily determinable fair values will be applied prospectively to all equity investments that exist as of the date of adoption of the standard.

For public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2017. We will adopt ASU 2016-01 on January 1, 2018 as required and do not expect it to materially affect our financial condition, results of operations or cash flows. We will make the required changes to our disclosures upon adoption.

ASU 2016-02, “Leases”: 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 U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting and ASU 2014-09. ASU 2016-02 also requires qualitative disclosures along with specific quantitative disclosures for both lessees and lessors.

For public entities, ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and is effective for interim periods in the year of adoption. The standard 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 optional 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 recognize 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 standard on our ongoing financial reporting, and have not yet selected the year in which we will adopt the standard.

ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships”: ASU 2016-05 provides clarification that a change in the counterparty to a derivative instrument that has been designated as a hedging instrument does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. ASU 2016-05 may be adopted prospectively or using a modified retrospective approach. We prospectively adopted ASU 2016-05 on January 1, 2016, and it did not affect our financial condition, results of operations or cash flows.

ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting”: ASU 2016-09 is intended to simplify several aspects of the accounting for employee share-based payment transactions. Under ASU 2016-09, excess tax benefits and tax deficiencies are required to be recorded in earnings, and the requirement to reclassify excess tax benefits from operating to financing activities on the statement of cash flows has been eliminated. ASU 2016-09 also allows entities to withhold taxes up to the maximum individual statutory tax rate without resulting in liability classification of the award and clarifies that cash payments made to taxing authorities in connection with withheld shares should be classified as financing activities in the statement of cash flows. Additionally, the standard provides for an accounting policy election to either continue to estimate forfeitures or account for them as they occur. For public entities, ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted, and is effective for interim periods in the year of adoption.

We early adopted the provisions of ASU 2016-09 during the three months ended September 30, 2016, with an effective date of January 1, 2016. Upon adoption:


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

▪

Sempra Energy, SDG&E and SoCalGas recognized earnings consisting of excess tax benefits on the Condensed Consolidated Statements of Operations of $34 million, $7 million and $4 million, respectively, in the nine months ended September 30, 2016, all of which related to the three months ended March 31, 2016. The $34 million was previously recorded in Sempra Energy Shareholders’ Equity in Common Stock prior to adoption of ASU 2016-09.


▪	The $34 million of excess tax benefits from share-based compensation for Sempra Energy related to the three months ended March 31, 2016 was previously classified as a financing activity on Sempra Energy’s Condensed Consolidated Statement of Cash Flows. As now required, the $34 million of excess tax benefits for Sempra Energy, as well as the $7 million for SDG&E and $4 million for

SoCalGas, are included in Cash Flows From Operating Activities on the Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2016. This amendment was adopted prospectively, and therefore, we have not adjusted the Condensed Consolidated Statements of Cash Flows for the prior period presented.

▪

As a result of the provision to recognize excess tax benefits in earnings, these benefits are no longer included in the calculation of diluted earnings per share (EPS) effective January 1, 2016. The weighted-average number of common shares outstanding for diluted EPS increased by 75 thousand shares for the three months ended March 31, 2016 and 98 thousand shares and 89 thousand shares for the three months and six months ended June 30, 2016, respectively. We discuss the impact further in Note 5 under “Earnings Per Share.”

Upon adoption of ASU 2016-09, we elected to continue estimating the number of awards expected to be forfeited and adjusting our estimate on an ongoing basis. All other provisions of ASU 2016-09 did not impact our financial condition, results of operations or cash flows.

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 year in which we will adopt the standard and its effect on our ongoing financial reporting.

ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments”: 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 in order to reduce diversity in practice.

For public entities, ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted, and is effective for interim periods in the year of adoption. An entity that elects early adoption must adopt all of the amendments in the same period. Entities must apply the guidance retrospectively to all periods presented, but may apply it prospectively if retrospective application would be impracticable. We are currently evaluating the year in which we will adopt the standard and its effect on our ongoing financial reporting.

NOTE 3. 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 Mexico

Gasoductos de Chihuahua S. de R.L. de C.V. (GdC)

Background and Financing. In July 2015, IEnova entered into an agreement to purchase Petróleos Mexicanos’ (or PEMEX, the Mexican state-owned oil company) 50-percent interest in GdC. GdC develops and operates energy infrastructure in Mexico. On September 21, 2016, IEnova received approval for the acquisition from Mexico’s Comisión Federal de Competencia Económica (COFECE or Mexican Competition Commission). On September 26, 2016, IEnova completed the acquisition of PEMEX’s 50-percent interest in GdC for a purchase price of $1.144 billion (exclusive of $66 million of cash and cash equivalents acquired), plus the assumption of $364 million of long-term debt, increasing IEnova’s ownership interest in GdC to 100 percent. GdC became a consolidated subsidiary of IEnova on this date. Prior to the acquisition date, IEnova owned 50 percent of GdC and accounted for its interest as an equity method investment.

The assets involved in the acquisition include three natural gas pipelines, an ethane pipeline, and a liquid petroleum gas pipeline and associated storage terminal. The transaction excludes the Los Ramones Norte pipeline, in which IEnova will continue holding an indirect 25-percent ownership interest through GdC’s interest in Ductos y Energéticos del Norte, S. de R.L. de C.V. (DEN). As of the acquisition date, IEnova continues to hold a 50-percent interest in DEN through GdC and accounts for it as an equity method

investment. PEMEX continues to hold its 50-percent interest in DEN, which enables us to have an ongoing relationship with PEMEX for joint development of new projects in the future.

We paid $1.078 billion in cash ($1.144 billion purchase price less $66 million of cash and cash equivalents acquired), which was funded using interim financing provided by Sempra Global through a $1.150 billion bridge loan to IEnova. Sempra Global funded the transaction using commercial paper borrowings. On October 19, 2016, IEnova completed a private follow-on offering of its common stock in the U.S. and outside of Mexico and a concurrent public common stock offering in Mexico, which generated net proceeds of approximately $1.57 billion or 29.86 billion Mexican pesos (based on an exchange rate of 18.96 pesos to 1.00 U.S. dollar as of October 13, 2016). IEnova used a portion of the proceeds from the offerings to fully repay the Sempra Global bridge loan in October 2016. We discuss the offerings in Note 13.

Purchase Price Allocation. We accounted for this business combination using the acquisition method of accounting whereby the total fair value of the business acquired is allocated to identifiable assets acquired and liabilities assumed based on respective fair values, with any excess recognized as goodwill at the Sempra Mexico reportable segment. We expect the GdC acquisition to have strategic benefits, including opportunities for asset optimization and expansion into areas such as the transportation and storage of refined products; and a larger platform and presence in Mexico to participate in energy sector reform, reflecting the value of goodwill recognized. None of the goodwill is expected to be deductible in Mexico or the United States for income tax purposes.

The following table summarizes the total fair value of the business combination and the values of the assets acquired and liabilities assumed at the date of acquisition:



PURCHASE PRICE ALLOCATION – GdC
(Dollars in millions)
		September 26, 2016
Fair value of business combination:
Cash consideration (fair value of total consideration)		$	1,144
Fair value of equity interest in GdC immediately prior to acquisition		1,144
Total fair value of business combination		$	2,288

Recognized amounts of identifiable assets acquired and liabilities assumed:
Cash and cash equivalents		$	66
Accounts receivable(1)		39
Other current assets		6
Property, plant and equipment		1,248
Other noncurrent assets		1
Accounts payable		(11		)
Due to unconsolidated affiliates		(3		)
Current portion of long-term debt		(49		)
Fixed-price contracts and other derivatives, current		(6		)
Other current liabilities		(20		)
Long-term debt		(315		)
Asset retirement obligations		(5		)
Deferred income taxes		(8		)
Fixed-price contracts and other derivatives, noncurrent		(19		)
Other noncurrent liabilities		(11		)
Total identifiable net assets		913
Goodwill		1,375
Total fair value of business combination		$	2,288
(1)	We expect acquired accounts receivable to be substantially realizable in cash. Accounts receivable are net of negligible collection allowances.

Gain on Remeasurement of Equity Method Investment. Our results in the three months and nine months ended September 30, 2016, include a pretax gain of $617 million ($432 million after-tax) for the excess of the acquisition-date fair value of Sempra Mexico’s previously held equity interest in GdC over the carrying value of that interest, included as Remeasurement of Equity Method Investment on the Sempra Energy Condensed Consolidated Statements of Operations. We used a market approach to measure the acquisition-date fair value of IEnova’s equity interest in GdC immediately prior to the business acquisition. We discuss non-recurring fair value measures and the associated accounting impact of the GdC acquisition in Note 8.

Valuation of GdC’s Assets and Liabilities. Based on the nature of the Mexico regulatory environment and the oversight surrounding the establishment and maintenance of rates that GdC charges for services on its assets, GdC applies the guidance under the provisions of U.S. GAAP governing rate-regulated operations. Therefore, when determining the fair value of the acquired assets and liabilities

assumed, we considered the effect of regulation on a market participant’s view of the highest and best use of the assets, in particular for the fair value of GdC’s property, plant and equipment (PP&E). Under U.S. GAAP, regulation is viewed as being a characteristic (restriction) of a regulated entity’s PP&E, and the impact of regulation is considered a fundamental input to measuring the fair value of PP&E in a business combination involving a regulated business. As a regulated business will generally earn a return of its costs and a reasonable return on its invested capital, but nothing more, the value of a regulated business is the value of its invested capital.

Under this premise, the fair value of the PP&E of a regulated business is generally assumed to be equivalent to carrying value for financial reporting purposes. Management has concluded that the carrying value of GdC’s PP&E is representative of fair value.

We applied an income approach, specifically the discounted cash flow method, to measure the fair value of debt and derivatives. We valued debt by discounting future debt payments by a market yield and we valued derivatives by discounting the future interest payments under the fixed and floating rates using current market data.

For substantially all other assets and liabilities, our analysis indicates that historical carrying value approximates fair value due to their short-term nature.

Impact on Operating Results. We incurred acquisition costs of $2 million in the three months and nine months ended September 30, 2016, and $1 million in the three months and nine months ended September 30, 2015. These costs are included in Operation and Maintenance Expense on the Sempra Energy Condensed Consolidated Statements of Operations.

For the three months and nine months ended September 30, 2016, the Sempra Energy Condensed Consolidated Statements of Operations include $3 million of revenues and $1 million of losses (after noncontrolling interest) from GdC since the September 26, 2016 date of acquisition.

The following table presents the pro forma results for the three months and nine months ended September 30, 2016 and 2015. The pro forma financial information combines the historical results of operations of Sempra Energy and GdC as though the acquisition occurred on January 1, 2015. The pro forma information is not necessarily indicative of results that would have been achieved had the business been combined during the periods presented or the results that we will experience going forward.



PRO FORMA INFORMATION – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Revenues	$	2,608	$	2,545	$	7,529	$	7,708
Net income	308		308		744		1,550
Earnings	299		255		685		1,280

The pro forma information above assumes:


▪	the related IEnova equity offerings, discussed above and in Note 13, occurred on January 1, 2015, which results in a change in Sempra Energy’s noncontrolling interest in IEnova from 18.9 percent to 33.6 percent for all periods presented;


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


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


▪	the gain related to the remeasurement of our previously held equity interest in GdC has been included in the nine months ended September 30, 2015, and accordingly, the three months and nine months ended September 30, 2016 were adjusted to exclude the gain; and


▪	acquisition-related transaction costs have been included in the nine months ended September 30, 2015, and accordingly, the three months and nine months ended September 30, 2016 were adjusted to exclude them.

Most of Sempra Mexico’s operations, including GdC, use the U.S. dollar as their functional currency.

Sempra Renewables

In July 2016, Sempra Renewables acquired a 100-percent interest in the Apple Blossom Wind project, a 100-megawatt (MW) wind farm currently under construction in Huron County, Michigan, for a total purchase price of $22 million. Sempra Renewables paid $18 million in cash on the July 1, 2016 acquisition date and anticipates paying the remaining $4 million on achievement of certain construction milestones in the fourth quarter of 2016. The wind farm has a 15-year power purchase agreement with Consumers Energy that will commence upon commercial operation, expected in late 2017.

In March 2015, Sempra Renewables invested $8 million to acquire a 100-percent interest in the Black Oak Getty Wind project, a 78-MW wind farm currently under construction in Stearns County, Minnesota. The wind farm has a 20-year power purchase agreement with Minnesota Municipal Power Agency that will commence upon commercial operation, expected in late 2016.

PENDING ACQUISITION

Sempra Mexico

On September 5, 2016, IEnova entered into an agreement to acquire 100 percent of the equity interests in the Ventika I and Ventika II (collectively, Ventika) wind power generation facilities for an estimated purchase price of $852 million, which includes the assumption of approximately $477 million of existing debt, subject to normal adjustments at closing. Ventika is a 252-MW wind farm located in Nuevo Leon, Mexico, which began commercial operations in April 2016. All of Ventika’s generation capacity is contracted under 20-year, U.S. dollar-denominated power purchase agreements with five private off-takers. We expect the acquisition to be completed in the fourth quarter of 2016, subject to the satisfaction of customary closing conditions, including receipt of approval from the COFECE. The acquisition will be partially funded through debt financing at IEnova and a portion of the proceeds from the IEnova equity offerings that we discuss in Note 13.

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

In February 2016, management approved a plan to market and sell Sempra Mexico’s Termoeléctrica de Mexicali (TdM), a 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As a result, we stopped depreciating the plant and classified it as held for sale.

In connection with the sales process, in September 2016, Sempra Mexico obtained market information indicating that the fair value of TdM may be less than its carrying value. After performing an analysis of the information, Sempra Mexico reduced the carrying value of TdM by recognizing a noncash impairment charge of $131 million ($111 million after-tax) in the three months and nine months ended September 30, 2016 in Impairment Losses on Sempra Energy’s Condensed Consolidated Statements of Operations. We discuss non-recurring fair value measures and the associated accounting impact on TdM in Note 8.

In connection with classifying TdM as held for sale, we recognized $32 million in income tax expense in the first half of 2016 for a deferred Mexican income tax liability related to the excess of carrying value over the tax basis. As a result of reducing the carrying value of TdM in the third quarter of 2016, we reduced the deferred Mexican income tax liability by $31 million. As the Mexican income tax on this basis difference is based on current carrying value, foreign exchange rates and inflation, such amount could change in future periods until the date of sale. We expect to complete the sale in the first half of 2017.

At September 30, 2016, 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 SEPTEMBER 30, 2016
(Dollars in millions)
	Termoeléctrica de Mexicali
Cash and cash equivalents	$	1
Inventories	8
Other current assets	25
Deferred income taxes	5
Other assets	22
Property, plant and equipment, net	120
Total assets held for sale	$	181

Accounts payable	$	1
Other current liabilities	7
Asset retirement obligations	4
Other liabilities	23
Total liabilities held for sale	$	35

DIVESTITURES

Sempra Natural Gas

EnergySouth Inc.

In April 2016, Sempra Natural Gas signed a definitive agreement to sell 100 percent of the outstanding equity of EnergySouth Inc. (EnergySouth), the parent company of Mobile Gas and Willmut Gas, to Spire Inc., formerly The Laclede Group, Inc. On September 12, 2016, Sempra Natural Gas completed the sale for cash proceeds of $318 million, net of $2 million cash sold, with the buyer assuming debt of $67 million. We recognized a pretax gain on the sale of $130 million ($78 million after-tax) in the three months and nine months ended September 30, 2016, in Gain on Sale of Assets on Sempra Energy’s Condensed Consolidated Statements of Operations. As we discuss in Note 11, litigation and any associated liabilities and insurance receivable at Mobile Gas were retained by Mobile Gas at the close of the transaction. On September 12, 2016, Sempra Natural Gas deconsolidated EnergySouth.

The following table summarizes the deconsolidation:



DECONSOLIDATION OF SUBSIDIARY
(Dollars in millions)
		EnergySouth Inc.
Proceeds from sale, net of transaction costs		$	304
Cash		(2		)
Inventory		(3		)
Other current assets		(14		)
Regulatory assets		(12		)
Goodwill		(72		)
Other assets		(53		)
Property, plant and equipment, net		(199		)
Accounts payable		12
Other current liabilities		13
Long-term debt		67
Deferred income taxes		36
Regulatory liabilities		23
Asset retirement obligations		12
Other liabilities		18
Gain on sale of business(1)		$	130
(1)	Included in Gain on Sale of Assets on Sempra Energy’s Condensed Consolidated Statements of Operations.

Investment in Rockies Express Pipeline LLC

In March 2016, Sempra Natural Gas entered into an agreement to sell its 25-percent interest in Rockies Express Pipeline LLC (Rockies Express) to a subsidiary of Tallgrass Development, LP for cash consideration of $440 million, subject to adjustment at closing. The transaction closed in May 2016 for total cash proceeds of $443 million.

At the date of the agreement, the carrying value of Sempra Natural Gas’ investment in Rockies Express was $484 million. Following the execution of the agreement, Sempra Natural Gas measured the fair value of its equity method investment at $440 million, and recognized a $44 million ($27 million after-tax) impairment in Equity Earnings, Before Income Tax, on the Sempra Energy Condensed Consolidated Statement of Operations in the first quarter of 2016. We discuss non-recurring fair value measures and the associated accounting impact on our investment in Rockies Express in Note 8.

In the second quarter of 2016, Sempra Natural Gas permanently released pipeline capacity that it held with Rockies Express and others, as we discuss in Note 11.

Mesquite Power Plant

In April 2015, Sempra Natural Gas sold the remaining 625-MW block of the Mesquite Power plant, together with a related power sales contract, for net cash proceeds of $347 million. We recognized a pretax gain on the sale of $61 million ($36 million after-tax), included in Gain on Sale of Assets on the Sempra Energy Condensed Consolidated Statements of Operations for the nine months ended September 30, 2015.

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

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

SEMPRA MEXICO

As we discuss in Note 3, on September 26, 2016, IEnova completed the acquisition of the remaining 50-percent interest in GdC and GdC became a consolidated subsidiary. Prior to the acquisition date, IEnova owned 50 percent of GdC and accounted for its interest as an equity method investment. As of the acquisition date, IEnova accounts for GdC’s 50-percent interest in DEN as an equity method investment.

In June 2016, Infraestructura Marina del Golfo (IMG), a joint venture between IEnova and a subsidiary of TransCanada Corporation (TransCanada), was awarded the right to build, own and operate the Sur de Texas – Tuxpan natural gas pipeline by the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE). IEnova has a 40-percent interest in the project and TransCanada owns the remaining 60-percent interest. The project is expected to be completed in late 2018 and is fully contracted under a 25-year natural gas transportation service contract with the CFE. During the nine months ended September 30, 2016, Sempra Mexico invested cash of $56 million in the joint venture.

SEMPRA RENEWABLES

Sempra Renewables invested cash of $18 million in its joint ventures during both the nine months ended September 30, 2016 and 2015.

SEMPRA NATURAL GAS

Sempra Natural Gas capitalized $36 million of interest during both the nine months ended September 30, 2016 and 2015 related to its investment in Cameron LNG Holdings, LLC (Cameron LNG JV), which has not commenced planned principal operations. In addition, during the nine months ended September 30, 2015, Sempra Natural Gas invested cash of $10 million in the joint venture.

In May 2016, Sempra Natural Gas sold its 25-percent interest in Rockies Express, as we discuss in Note 3. In April 2015, Sempra Natural Gas invested $113 million of cash in Rockies Express to repay project debt that matured in early 2015.

GUARANTEES

We discuss guarantees that we have provided in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report. These guarantees have a maximum aggregate amount of $4.5 billion and an aggregate carrying value of $58 million at September 30, 2016.

NOTE 5. OTHER FINANCIAL DATA

INVENTORIES

The components of inventories by segment are as follows:



INVENTORY BALANCES
(Dollars in millions)
	Natural gas				Liquefied natural gas				Materials and supplies				Total
	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
SDG&E	$	1	$	6	$	—	$	—	$	72	$	69	$	73	$	75
SoCalGas(1)	24		49		—		—		53		30		77		79
Sempra South American Utilities	—		—		—		—		46		30		46		30
Sempra Mexico	—		—		4		3		2		10		6		13
Sempra Renewables	—		—		—		—		3		3		3		3
Sempra Natural Gas	94		94		3		3		—		1		97		98
Sempra Energy Consolidated	$	119	$	149	$	7	$	6	$	176	$	143	$	302	$	298


(1)	At both September 30, 2016 and December 31, 2015, SoCalGas’ natural gas inventory for core customers is net of an inventory loss related to the Aliso Canyon natural gas leak, which we discuss in Note 11.

Temporary LIFO Liquidation

The California Utilities value natural gas inventory using the last-in first-out (LIFO) method. As inventories are sold, differences between the LIFO valuation and the estimated replacement cost are reflected in customer rates. These differences are generally temporary, but may become permanent. For interim periods, temporary LIFO liquidation represents the difference between the carrying value of natural gas inventory withdrawn from storage during the period for delivery to customers and the projected cost of the replacement of that inventory by year end. At September 30, 2016, temporary LIFO liquidation of $8 million is recorded in Other Assets on the Sempra Energy and SoCalGas Condensed Consolidated Balance Sheets. SoCalGas estimates that by December 31, 2016, temporary LIFO liquidation may not be replenished, and may result in a permanent LIFO liquidation of approximately $10 million to $15 million. This change in natural gas cost would be recovered in rates.

GOODWILL

We discuss goodwill in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Changes in the carrying amount of goodwill on the Sempra Energy Consolidated Balance Sheets are as follows:



GOODWILL
(Dollars in millions)
		Sempra South American Utilities		Sempra Mexico		Sempra Natural Gas			Total
Balance at December 31, 2015		$	722	$	25	$	72		$	819
Acquisition of business		—		1,375		—			1,375
Sale of business		—		—		(72		)	(72		)
Foreign currency translation(1)		28		—		—			28
Balance at September 30, 2016		$	750	$	1,400	$	—		$	2,150
(1)	We record the offset of this fluctuation to Other Comprehensive Income (Loss).

In September 2016, Sempra Mexico recorded goodwill of $1,375 million in connection with the acquisition of GdC, and Sempra Natural Gas reduced goodwill by $72 million in connection with the sale of EnergySouth. We discuss this acquisition and divestiture in Note 3.

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

SDG&E

SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various power purchase arrangements which 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 upon 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 an agreement to purchase power generated at the Otay Mesa Energy Center (OMEC), a 605-MW generating facility. In addition to tolling, the agreement provides SDG&E with the option to purchase OMEC at the end of the contract term in 2019, or upon earlier termination of the purchased-power agreement, at a predetermined price subject to adjustments based on performance of the facility. If SDG&E does not exercise its option, under certain circumstances, it may be required to purchase the power plant at a predetermined price, which we refer to as the put option.

The facility owner, Otay Mesa Energy Center LLC (OMEC LLC), is a VIE (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 have consolidated Otay Mesa VIE. Otay Mesa VIE’s equity of $50 million at September 30, 2016 and $53 million at December 31, 2015 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 $307 million at September 30, 2016, the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is secured by OMEC’s property, plant and equipment. SDG&E is not a party to the loan agreement and does not have any additional implicit or explicit financial responsibility to OMEC LLC. The loan fully matures in April 2019 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 7.

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 generally correspond to SDG&E’s Condensed Consolidated Statements of Operations.



AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
Operating expenses
Cost of electric fuel and purchased power	$	(28	)	$	(27	)	$	(62	)	$	(66	)
Operation and maintenance	4			3			23			13
Depreciation and amortization	8			7			25			19
Total operating expenses	(16		)	(17		)	(14		)	(34		)
Operating income	16			17			14			34
Interest expense	(5		)	(5		)	(15		)	(14		)
Income (loss) before income taxes/Net income (loss)	11			12			(1		)	20
(Earnings) losses attributable to noncontrolling interest	(11		)	(12		)	1			(20		)
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 variable interest entity at September 30, 2016. In addition to the tolling agreements described above, other variable interests involve various elements of fuel and power costs, and other components of cash flow 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. 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 are not expected to significantly affect the financial position, results of operations, or liquidity of SDG&E. 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. We provide additional information about power purchase agreements with peaker 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 Natural Gas

Sempra Energy’s equity method investment in Cameron LNG JV is a VIE principally due to contractual provisions that transfer certain risks to customers. Sempra Energy is not the primary beneficiary because we do not have the power to direct the most significant activities of Cameron LNG JV. We will continue to evaluate Cameron LNG JV for any changes that may impact our determination of the primary beneficiary. The carrying value of our investment in Cameron LNG JV, including amounts recognized in Accumulated Other Comprehensive Income (Loss) (AOCI) related to interest-rate cash flow hedges at Cameron LNG JV, was $838 million at September 30, 2016 and $983 million at December 31, 2015. Our maximum exposure to loss includes the carrying value of our investment and the guarantees discussed above in Note 4 and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Variable Interest Entities

Sempra Energy’s other operating units 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 companies that are VIEs. As the primary beneficiary of these service 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

Net Periodic Benefit Cost

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



NET PERIODIC BENEFIT COST – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	Three months ended September 30,
	2016			2015			2016			2015
Service cost	$	26		$	27		$	4		$	5
Interest cost	40			38			9			10
Expected return on assets	(41		)	(42		)	(17		)	(17		)
Amortization of:
Prior service cost (credit)	2			3			—			(1		)
Actuarial loss (gain)	10			9			(1		)	—
Settlements	—			4			—			—
Regulatory adjustment	(28		)	(27		)	5			4
Total net periodic benefit cost	$	9		$	12		$	—		$	1

	Nine months ended September 30,
	2016			2015			2016			2015
Service cost	$	81		$	86		$	15		$	19
Interest cost	120			116			31			33
Expected return on assets	(124		)	(130		)	(52		)	(51		)
Amortization of:
Prior service cost (credit)	8			8			—			(2		)
Actuarial loss (gain)	23			28			(1		)	—
Settlements	—			4			—			—
Regulatory adjustment	(84		)	(86		)	9			4
Total net periodic benefit cost	$	24		$	26		$	2		$	3



NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	Three months ended September 30,
	2016			2015			2016			2015
Service cost	$	7		$	6		$	1		$	1
Interest cost	10			9			2			2
Expected return on assets	(12		)	(14		)	(3		)	(2		)
Amortization of:
Actuarial loss	2			3			—			—
Regulatory adjustment	(7		)	(3		)	—			(1		)
Total net periodic benefit cost	$	—		$	1		$	—		$	—

	Nine months ended September 30,
	2016			2015			2016			2015
Service cost	$	22		$	22		$	3		$	5
Interest cost	31			29			6			6
Expected return on assets	(37		)	(41		)	(8		)	(8		)
Amortization of:
Prior service cost	1			1			2			2
Actuarial loss (gain)	7			7			(1		)	—
Regulatory adjustment	(22		)	(15		)	(2		)	(5		)
Total net periodic benefit cost	$	2		$	3		$	—		$	—



NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
	Pension benefits						Other postretirement benefits
	Three months ended September 30,
	2016			2015			2016			2015
Service cost	$	16		$	17		$	4		$	3
Interest cost	26			25			7			8
Expected return on assets	(26		)	(25		)	(15		)	(14		)
Amortization of:
Prior service cost (credit)	3			2			(1		)	(2		)
Actuarial loss	3			5			—			—
Regulatory adjustment	(21		)	(24		)	5			5
Total net periodic benefit cost	$	1		$	—		$	—		$	—

	Nine months ended September 30,
	2016			2015			2016			2015
Service cost	$	51		$	55		$	11		$	13
Interest cost	76			74			24			26
Expected return on assets	(78		)	(79		)	(43		)	(42		)
Amortization of:
Prior service cost (credit)	7			6			(3		)	(6		)
Actuarial loss	8			16			—			—
Regulatory adjustment	(62		)	(71		)	11			9
Total net periodic benefit cost	$	2		$	1		$	—		$	—

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 2016:



BENEFIT PLAN CONTRIBUTIONS
(Dollars in millions)
	Sempra Energy Consolidated		SDG&E		SoCalGas
Contributions through September 30, 2016:
Pension plans	$	24	$	2	$	1
Other postretirement benefit plans	3		—		1
Total expected contributions in 2016:
Pension plans	$	124	$	7	$	73
Other postretirement benefit plans	6		2		1

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 $439 million and $464 million at September 30, 2016 and December 31, 2015, respectively.

EARNINGS PER SHARE

The following table provides EPS computations for the three months and nine months ended September 30, 2016 and 2015. 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 SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Numerator:
Earnings/Income attributable to common shares	$	622	$	248	$	991	$	980

Denominator:
Weighted-average common shares outstanding for basic EPS(1)	250,386		248,432		250,073		248,090
Dilutive effect of stock options, restricted stock awards and restricted stock units(2)	2,019		2,592		1,903		2,575
Weighted-average common shares outstanding for diluted EPS(2)	252,405		251,024		251,976		250,665

Earnings per share:
Basic	$	2.48	$	1.00	$	3.96	$	3.95
Diluted	2.46		0.99		3.93		3.91

(1)

Includes 572 and 504 average fully vested restricted stock units held in our Deferred Compensation Plan for the three months ended September 30, 2016 and 2015, respectively, and 565 and 486 of such units for the nine months ended September 30, 2016 and 2015, respectively. These fully vested restricted stock units are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.


(2)	Reflects the prospective adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2. Prior to the adoption, the dilutive effect of stock options, restricted stock awards and restricted stock units was reduced by excess tax benefits assumed to be used to repurchase shares on the open market.

The potentially dilutive impact from stock options, restricted stock awards (RSAs) and restricted stock units (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 excludes 2,426 RSUs for the nine months ended September 30, 2016 because to include them would be antidilutive for the period. However, these RSUs could potentially dilute basic EPS in the future. There were no antidilutive RSUs for the three months ended September 30, 2016, and there were no antidilutive stock options or RSAs for the three months and nine months ended September 30, 2016. There were no antidilutive RSUs, stock options or RSAs for the three months and nine months ended September 30, 2015.

Prior to adoption of ASU 2016-09 as of January 1, 2016, which we discuss in Note 2, excess tax benefits were also assumed to be used to repurchase shares on the open market when applying the treasury stock method. The excess tax benefits are tax deductions we would receive upon the assumed exercise of stock options and assumed vesting of RSAs and RSUs in excess of the deferred income taxes we recorded related to the compensation expense on such stock options, awards and units. Tax shortfalls occur when the assumed tax deductions are less than recorded deferred income taxes. Upon adoption of ASU 2016-09, as a result of the provision to recognize excess tax benefits and shortfalls in earnings, these benefits and shortfalls are no longer included in the calculation of diluted EPS beginning January 1, 2016.

Our performance-based RSUs include awards that vest at the end of three-year (for awards granted during or after 2015) or four-year performance periods based on Sempra Energy’s total return to shareholders relative to that of specified market indices (Total Shareholder Return or TSR RSUs) or based on the compound annual growth rate of Sempra Energy’s EPS (EPS RSUs). The comparative market indices for the TSR RSUs are the Standard & Poor’s (S&P) 500 Utilities Index and the S&P 500 Index. We primarily use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies to develop our EPS RSU targets. TSR RSUs represent the right to receive from zero to 1.5 shares (2.0 shares for awards granted during or after 2014) of Sempra Energy common stock if performance targets are met. EPS RSUs represent the right to receive from zero to 2.0 shares of Sempra Energy common stock if performance targets are met. If performance falls between the targets specified for each performance metric, we calculate the payout using linear interpolation. Participants also receive additional shares for dividend equivalents on shares subject to RSUs, which are deemed reinvested to purchase additional units that become subject to the same vesting conditions as the RSUs to which the dividends relate. We discuss performance-based RSU awards further in Note 8 of the Notes to Consolidated Financial Statements in our Annual Report.

Our RSAs, which are solely service-based, and those RSUs that are service-based or issued in connection with certain other performance goals represent the right to receive up to 1.0 share if the service requirements or certain other vesting conditions are met. These RSAs and RSUs have the same dividend equivalent rights as the performance-based RSUs described above. We include RSAs and these RSUs in potential dilutive shares at 100 percent, subject to the application of the treasury stock method. We include our TSR

RSUs and EPS RSUs in potential dilutive shares at zero to up to 200 percent to the extent that they currently meet the performance requirements for vesting, subject to the application of the treasury stock method. Due to market fluctuations of both Sempra Energy stock and the comparative indices, dilutive TSR RSU shares may vary widely from period-to-period. If it were assumed that performance goals for all performance-based RSUs were met at maximum levels and if the treasury stock method were not applied to any of our RSAs or RSUs, the incremental potential dilutive shares would be 2,273,102 and 2,001,020 for the three months ended September 30, 2016 and 2015, respectively, and 2,406,512 and 2,047,656 for the nine months ended September 30, 2016 and 2015, respectively.

SHARE-BASED COMPENSATION

We discuss our share-based compensation plans in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report. We recorded share-based compensation expense, net of income taxes, of $7 million for each of the three months ended September 30, 2016 and 2015, and $20 million and $22 million for the nine months ended September 30, 2016 and 2015, respectively. Pursuant to our Sempra Energy share-based compensation plans, Sempra Energy’s compensation committee granted 373,070 TSR RSUs, 94,760 EPS RSUs and 95,876 service-based RSUs during the nine months ended September 30, 2016, primarily in January.

During the nine months ended September 30, 2016, IEnova issued 378,367 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.

CAPITALIZED FINANCING COSTS

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

The following table shows capitalized financing costs for the three months and nine months ended September 30, 2016 and 2015.



CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2016		2015		2016		2015
Sempra Energy Consolidated:
AFUDC related to debt	$	7	$	6	$	22	$	19
AFUDC related to equity	29		26		86		84
Other capitalized interest	26		18		64		52
Total Sempra Energy Consolidated	$	62	$	50	$	172	$	155
SDG&E:
AFUDC related to debt	$	4	$	3	$	12	$	10
AFUDC related to equity	11		9		35		27
Total SDG&E	$	15	$	12	$	47	$	37
SoCalGas:
AFUDC related to debt	$	3	$	3	$	10	$	9
AFUDC related to equity	10		10		30		29
Other capitalized interest	1		1		1		1
Total SoCalGas	$	14	$	14	$	41	$	39

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 noncontrolling interests:



CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Foreign currency translation adjustments			Financial instruments			Pension and other postretirement benefits			Total accumulated other comprehensive income (loss)
	Three months ended September 30, 2016 and 2015
2016:
Balance as of June 30, 2016	$	(503	)	$	(264	)	$	(85	)	$	(852	)
Other comprehensive (loss) income before
reclassifications	(28		)	8			—			(20		)
Amounts reclassified from accumulated other
comprehensive income	—			5			2			7
Net other comprehensive (loss) income	(28		)	13			2			(13		)
Balance as of September 30, 2016	$	(531	)	$	(251	)	$	(83	)	$	(865	)
2015:
Balance as of June 30, 2015	$	(427	)	$	(86	)	$	(83	)	$	(596	)
Other comprehensive loss before
reclassifications	(92		)	(79		)	—			(171		)
Amounts reclassified from accumulated other
comprehensive income	—			1			5			6
Net other comprehensive (loss) income	(92		)	(78		)	5			(165		)
Balance as of September 30, 2015	$	(519	)	$	(164	)	$	(78	)	$	(761	)

	Nine months ended September 30, 2016 and 2015
2016:
Balance as of December 31, 2015	$	(582	)	$	(137	)	$	(87	)	$	(806	)
Other comprehensive income (loss) before
reclassifications	51			(122		)	—			(71		)
Amounts reclassified from accumulated other
comprehensive income	—			8			4			12
Net other comprehensive income (loss)	51			(114		)	4			(59		)
Balance as of September 30, 2016	$	(531	)	$	(251	)	$	(83	)	$	(865	)
2015:							.
Balance as of December 31, 2014	$	(322	)	$	(90	)	$	(85	)	$	(497	)
Other comprehensive loss before
reclassifications	(197		)	(76		)	—			(273		)
Amounts reclassified from accumulated other
comprehensive income	—			2			7			9
Net other comprehensive (loss) income	(197		)	(74		)	7			(264		)
Balance as of September 30, 2015	$	(519	)	$	(164	)	$	(78	)	$	(761	)


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



CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SOUTHERN CALIFORNIA GAS COMPANY
(Dollars in Millions)
	Financial instruments			Pension and other postretirement benefits			Total accumulated other comprehensive income (loss)
	Three months ended September 30, 2016 and 2015
2016:
Balance as of June 30, 2016	$	(14	)	$	(5	)	$	(19	)
Amounts reclassified from accumulated other
comprehensive income	1			—			1
Net other comprehensive income	1			—			1
Balance as of September 30, 2016	$	(13	)	$	(5	)	$	(18	)
2015:
Balance as of June 30 and September 30, 2015	$	(14	)	$	(4	)	$	(18	)

	Nine months ended September 30, 2016 and 2015
2016:
Balance as of December 31, 2015	$	(14	)	$	(5	)	$	(19	)
Amounts reclassified from accumulated other
comprehensive income	1			—			1
Net other comprehensive income	1			—			1
Balance as of September 30, 2016	$	(13	)	$	(5	)	$	(18	)
2015:
Balance as of December 31, 2014 and September 30, 2015	$	(14	)	$	(4	)	$	(18	)
(1) All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.



RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated other comprehensive income (loss) components	Amounts reclassified from accumulated other comprehensive income (loss)						Affected line item on Condensed Consolidated Statements of Operations
	Three months ended September 30,
	2016			2015
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments	$	4		$	5		Interest Expense
Interest rate instruments	3			3			Equity Earnings, Before Income Tax
Interest rate and foreign exchange instruments	7			—			Remeasurement of Equity Method Investment
Interest rate and foreign exchange instruments	(2		)	—			Equity Earnings, Net of Income Tax
Commodity contracts not subject to rate recovery	—			(3		)	Revenues: Energy-Related Businesses
Total before income tax	12			5
	(3		)	(1		)	Income Tax Expense
Net of income tax	9			4
	(4		)	(3		)	Earnings Attributable to Noncontrolling Interests
	$	5		$	1
Pension and other postretirement benefits:
Amortization of actuarial loss	$	4		$	7		See note (1) below
	(2		)	(2		)	Income Tax Expense
Net of income tax	$	2		$	5

Total reclassifications for the period, net of tax	$	7		$	6
SDG&E:
Financial instruments:
Interest rate instruments	$	3		$	3		Interest Expense
	(3		)	(3		)	(Earnings) Losses Attributable to Noncontrolling Interest
Total reclassifications for the period, net of tax	$	—		$	—
SoCalGas:
Financial instruments:
Interest rate instruments	$	1		$	—		Interest Expense
Total reclassifications for the period, net of tax	$	1		$	—


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



RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated other comprehensive income (loss) components	Amounts reclassified from accumulated other comprehensive income (loss)						Affected line item on Condensed Consolidated Statements of Operations
	Nine months ended September 30,
	2016			2015
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments	$	11		$	14		Interest Expense
Interest rate instruments	8			9			Equity Earnings, Before Income Tax
Interest rate and foreign exchange instruments	7			—			Remeasurement of Equity Method Investment
Interest rate and foreign exchange instruments	4			—			Equity Earnings, Net of Income Tax
Commodity contracts not subject to rate recovery	(7		)	(10		)	Revenues: Energy-Related Businesses
Total before income tax	23			13
	(4		)	(1		)	Income Tax Expense
Net of income tax	19			12
	(11		)	(10		)	Earnings Attributable to Noncontrolling Interests
	$	8		$	2
Pension and other postretirement benefits:
Amortization of actuarial loss	$	8		$	11		See note (1) below
	(4		)	(4		)	Income Tax Expense
Net of income tax	$	4		$	7

Total reclassifications for the period, net of tax	$	12		$	9
SDG&E:
Financial instruments:
Interest rate instruments	$	9		$	9		Interest Expense
	(9		)	(9		)	(Earnings) Losses Attributable to Noncontrolling Interest
Total reclassifications for the period, net of tax	$	—		$	—
SoCalGas:
Financial instruments:
Interest rate instruments	$	1		$	—		Interest Expense
Total reclassifications for the period, net of tax	$	1		$	—


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

For the three months and nine months ended September 30, 2016 and 2015, Other Comprehensive Income (Loss) (OCI), excluding amounts attributable to noncontrolling interests, at SDG&E was negligible.

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS

The following tables provide reconciliations of changes in Sempra Energy’s, SDG&E’s and SoCalGas’ shareholders’ equity and noncontrolling interests for the nine months ended September 30, 2016 and 2015.



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, 2015	$	11,809		$	770		$	12,579
Cumulative-effect adjustment from change in accounting principle	107			—			107
Comprehensive income	933			117			1,050
Preferred dividends of subsidiary	(1		)	—			(1		)
Share-based compensation expense	38			—			38
Common stock dividends declared	(565		)	—			(565		)
Issuances of common stock	80			—			80
Repurchases of common stock	(55		)	—			(55		)
Equity contributed by noncontrolling interests	—			2			2
Distributions to noncontrolling interests	—			(44		)	(44		)
Balance at September 30, 2016	$	12,346		$	845		$	13,191
Balance at December 31, 2014	$	11,326		$	774		$	12,100
Comprehensive income	717			56			773
Preferred dividends of subsidiary	(1		)	—			(1		)
Share-based compensation expense	39			—			39
Common stock dividends declared	(520		)	—			(520		)
Issuances of common stock	82			—			82
Repurchases of common stock	(74		)	—			(74		)
Tax benefit related to share-based compensation	56			—			56
Equity contributed by noncontrolling interest	—			1			1
Distributions to noncontrolling interests	—			(60		)	(60		)
Balance at September 30, 2015	$	11,625		$	771		$	12,396


(1)	Noncontrolling interests include the preferred stock of SoCalGas and other noncontrolling interests 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, 2015	$	5,223		$	53		$	5,276
Cumulative-effect adjustment from change in accounting principle	23			—			23
Comprehensive income	419			3			422
Common stock dividends declared	(175		)	—			(175		)
Equity contributed by noncontrolling interest	—			1			1
Distributions to noncontrolling interest	—			(7		)	(7		)
Balance at September 30, 2016	$	5,490		$	50		$	5,540
Balance at December 31, 2014	$	4,932		$	60		$	4,992
Comprehensive income	443			20			463
Common stock dividends declared	(150		)	—			(150		)
Distributions to noncontrolling interest	—			(16		)	(16		)
Balance at September 30, 2015	$	5,225		$	64		$	5,289



SHAREHOLDERS’ EQUITY – SOCALGAS
(Dollars in millions)
	SoCalGas shareholders’ equity
Balance at December 31, 2015	$	3,149
Cumulative-effect adjustment from change in accounting principle	15
Comprehensive income	200
Preferred stock dividends declared	(1		)
Balance at September 30, 2016	$	3,363
Balance at December 31, 2014	$	2,781
Comprehensive income	277
Preferred stock dividends declared	(1		)
Common stock dividends declared	(50		)
Balance at September 30, 2015	$	3,007

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 noncontrolling interests. As a result, noncontrolling interests are reported as a separate component of equity on the Condensed Consolidated Balance Sheets. Earnings or losses attributable to noncontrolling interests are separately identified on the Condensed Consolidated Statements of Operations, and comprehensive income or loss attributable to noncontrolling interests is separately identified on the Condensed Consolidated Statements of Comprehensive Income (Loss).

Preferred Stock

At Sempra Energy, the preferred stock of SoCalGas is presented as a noncontrolling interest and preferred stock dividends are charges against income related to noncontrolling interests. We provide additional information concerning preferred stock in Note 11 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Noncontrolling Interests

At September 30, 2016 and December 31, 2015, we reported the following noncontrolling ownership interests held by others (not including preferred shareholders) recorded 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 others
	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
SDG&E:
Otay Mesa VIE	100	%	100	%	$	50	$	53
Sempra South American Utilities:
Chilquinta Energía subsidiaries(1)	23.1 – 43.4		23.5 – 43.4		22		21
Luz del Sur	16.4		16.4		171		164
Tecsur	9.8		9.8		4		4
Sempra Mexico:
IEnova(2)	18.9		18.9		537		468
Sempra Natural Gas:
Bay Gas Storage Company, Ltd.	9.1		9.1		26		25
Liberty Gas Storage, LLC	23.3		23.2		14		14
Southern Gas Transmission Company	49.0		49.0		1		1
Total Sempra Energy					$	825	$	750


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

(2) On October 19, 2016, IEnova completed follow-on equity offerings that increased the 18.9 percent ownership held by others to 33.6 percent, as we discuss in Note 13.

Sempra Renewables

Sempra Renewables entered into a membership interest purchase agreement with a financial institution to form a portfolio tax equity partnership that includes Copper Mountain Solar 4, Mesquite Solar 2 and Mesquite Solar 3 (the tax equity portfolio). Under the purchase agreement, the formation of the portfolio tax equity partnership is subject to conditions precedent, including funding dates that correspond to each project’s completion. In July 2016, Sempra Renewables received the first funding in the form of a $78 million cash deposit, which has been recorded in Deferred Credits and Other on Sempra Energy’s Condensed Consolidated Balance Sheet at September 30, 2016. We expect the final funding date under the purchase agreement and formation of the portfolio tax equity partnership to occur in December 2016.

Sempra Renewables also entered into a membership interest purchase agreement with a financial institution to form a tax equity partnership involving the Black Oak Getty Wind project. The final funding date under the purchase agreement and formation of the tax equity partnership are subject to conditions precedent that we expect to occur in December 2016.

Sempra Renewables will continue to consolidate the tax equity portfolio and the Black Oak Getty Wind project. After the final funding dates, Sempra Renewables will report noncontrolling interests representing the financial institutions’ respective membership interests in the tax equity partnerships.

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)
	September 30, 2016			December 31, 2015
Sempra Energy Consolidated:
Total due from various unconsolidated affiliates - current	$	8		$	6

Sempra South American Utilities(1):
Eletrans S.A. and Eletrans II S.A.:
4% Note(2)	$	83		$	72
Other related party receivables	1			—
Sempra Mexico(1):
Affiliate of joint venture with DEN:
Note due November 13, 2017(3)	3			3
Note due November 14, 2018(3)	43			42
Note due November 14, 2018(3)	35			34
Note due November 14, 2018(3)	8			8
Energía Sierra Juárez:
Note due June 15, 2018(4)	14			24
Sempra Natural Gas:
Cameron LNG JV	8			3
Total due from unconsolidated affiliates - noncurrent	$	195		$	186

Total due to various unconsolidated affiliates - current	$	(9	)	$	(14	)
SDG&E:
Sempra Energy(5)	$	88		$	—
Other affiliates	—			1
Total due from unconsolidated affiliates - current	$	88		$	1

Sempra Energy	$	—		$	(34	)
SoCalGas	(5		)	(13		)
Other affiliates	(5		)	(8		)
Total due to unconsolidated affiliates - current	$	(10	)	$	(55	)

Income taxes due from Sempra Energy(6)	$	109		$	28
SoCalGas:
Sempra Energy(7)	$	30		$	35
SDG&E	5			13
Total due from unconsolidated affiliates - current	$	35		$	48

Income taxes due from Sempra Energy(6)	$	16		$	1


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


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


(3)	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 450 basis points (5.03 percent at September 30, 2016), to finance the Los Ramones Norte pipeline project.


(4)	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 637.5 basis points (6.91 percent at September 30, 2016), to finance the first phase of the Energía Sierra Juárez wind project, which is a joint venture of IEnova.


(5)	At September 30, 2016, net receivable included outstanding advances to Sempra Energy of $107 million at an interest rate of 0.60 percent.


(6)	SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from each company having always filed a separate return.


(7)	At September 30, 2016, net receivable included outstanding advances to Sempra Energy of $51 million at an interest rate of 0.57 percent. At December 31, 2015, net receivable included outstanding advances to Sempra Energy of $50 million at an interest rate of 0.11 percent.

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 September 30,				Nine months ended September 30,
	2016		2015		2016		2015
REVENUES
Sempra Energy Consolidated	$	5	$	6	$	15	$	22
SDG&E	2		3		5		8
SoCalGas	21		19		56		55
COST OF SALES
Sempra Energy Consolidated	$	10	$	29	$	60	$	78
SDG&E	16		15		46		33

Guarantees

Sempra Energy has provided guarantees to certain of its solar and wind farm joint ventures and entered into completion guarantees related to the financing of the Cameron LNG JV project, as we discuss above in Note 4 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 September 30,						Nine months ended September 30,
	2016			2015			2016			2015
Sempra Energy Consolidated:
Allowance for equity funds used during construction	$	29		$	26		$	86		$	84
Investment gains (losses)(1)	9			(12		)	29			(5		)
Losses on interest rate and foreign exchange instruments, net	(11		)	(4		)	(23		)	(7		)
Foreign currency transaction losses	(2		)	(3		)	(9		)	(6		)
Sale of other investments	1			2			3			8
Electrical infrastructure relocation income(2)	1			—			4			4
Regulatory interest, net(3)	1			1			4			3
Sundry, net	(2		)	2			4			7
Total	$	26		$	12		$	98		$	88
SDG&E:
Allowance for equity funds used during construction	$	11		$	9		$	35		$	27
Regulatory interest, net(3)	—			1			3			3
Sundry, net	—			(2		)	—			(4		)
Total	$	11		$	8		$	38		$	26
SoCalGas:
Allowance for equity funds used during construction	$	10		$	10		$	30		$	29
Regulatory interest, net(3)	1			—			1			—
Sundry, net	(3		)	(2		)	(7		)	(4		)
Total	$	8		$	8		$	24		$	25


(1)	Represents investment gains (losses) 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.


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


(3)	Interest on regulatory balancing accounts.

INCOME TAXES



INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Income tax expense		Effective income tax rate		Income tax expense (benefit)			Effective income tax rate
	Three months ended September 30,
	2016				2015
Sempra Energy Consolidated	$	282	29	%	$	15		6	%
SDG&E	91		32		75			29
SoCalGas	21		100		(20		)	71

	Nine months ended September 30,
	2016				2015
Sempra Energy Consolidated	$	284	21	%	$	276		22	%
SDG&E	204		33		217			32
SoCalGas	75		27		91			25

Sempra Energy, SDG&E and SoCalGas record income taxes for interim periods utilizing a forecasted effective tax rate anticipated for the full year, as required by U.S. GAAP. The income tax effect of items that can be reliably forecasted is factored into the forecasted effective tax rate, and the impact is recognized proportionately over the year. Items that cannot be reliably forecasted (e.g., resolution of prior years’ income tax items, remeasurement of deferred tax asset valuation allowances, Mexican currency translation and inflation adjustments, deferred income tax benefits associated with impairment of a book investment and certain impacts of regulatory matters) are recorded in the interim period in which they actually occur, which can result in variability in the effective income tax rate.

For SDG&E and SoCalGas, the California Public Utilities Commission (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 current effective income tax rate. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the effective income tax rate. 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 is also subject to flow-through treatment.

The final decision in the 2016 General Rate Case (2016 GRC) issued by the CPUC in June 2016 affecting the California Utilities requires the establishment of a two-way income tax expense memorandum account for SDG&E and SoCalGas to track any revenue variances resulting from certain differences arising between the income tax expense forecasted in the 2016 GRC and the income tax expense incurred from 2016 through 2018. The variances to be tracked include tax expense differences relating to


▪	net revenue changes,


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


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

The account will remain open, and the balance in the account will be reviewed in subsequent GRC proceedings, until the CPUC decides to close the account. We believe the future disposition of these tracked balances may result in refunds being directed to ratepayers to the extent tax expense incurred is lower than forecasted tax expense in the GRC process as a result of certain flow-through item deductions, as described above, or other items. We discuss the memo account further in Note 10.

Differences arising from the forecasted amounts will be tracked in the two-way income tax expense tracking account, except for the equity portion of AFUDC, which is not subject to taxation. We expect that certain amounts recorded in the tracking account may give rise to regulatory assets or liabilities until the CPUC disposes with the account. The CPUC tracking account does not affect the recovery of income tax expense in Federal Energy Regulatory Commission (FERC) formulaic rates.

In the third quarter of 2016, we adopted ASU 2016-09 with an effective date of January 1, 2016. ASU 2016-09 requires excess tax benefits and tax deficiencies related to employee share-based payment transactions to be recorded in earnings, instead of in shareholders’ equity. We discuss the impact of adopting the provisions of this standard in Note 2.

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

NOTE 6. DEBT AND CREDIT FACILITIES

LINES OF CREDIT

At September 30, 2016, Sempra Energy Consolidated had an aggregate of $4.3 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 which we describe below. Available unused credit on these lines at September 30, 2016 was approximately $2.0 billion. Our foreign operations have additional general purpose credit facilities aggregating $1.1 billion at September 30, 2016. Available unused credit on these lines totaled $429 million at September 30, 2016.

Sempra Energy

Sempra Energy has a $1 billion, five-year syndicated revolving credit agreement expiring in October 2020. On September 30, 2016, an additional lender was added to the facility. Citibank, N.A. serves as administrative agent for the syndicate of, now, 21 lenders, and no single lender has greater than a 7-percent share.

Borrowings bear interest at benchmark rates plus a margin that varies with Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At September 30, 2016, Sempra Energy was in compliance with this and all other financial covenants under the credit facility. 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.

At September 30, 2016, Sempra Energy had no outstanding borrowings or letters of credit supported by the facility.

Sempra Global

Sempra Global has a five-year syndicated revolving credit agreement expiring in October 2020. On September 30, 2016, an additional lender was added to the facility, and the borrowing capacity increased from $2.21 billion to $2.34 billion. Citibank, N.A. serves as administrative agent for the syndicate of, now, 21 lenders, and no single lender has greater than a 7-percent share.

Sempra Energy guarantees Sempra Global’s obligations under the credit facility. Borrowings bear interest at benchmark rates plus a margin that varies with Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At September 30, 2016, Sempra Energy was in compliance with this and all other financial covenants under the credit facility.

At September 30, 2016, Sempra Global had $2.26 billion of commercial paper outstanding supported by the facility and $79 million of available unused credit on the line.

California Utilities

SDG&E and SoCalGas have a combined $1 billion, five-year syndicated revolving credit agreement expiring in October 2020. On September 30, 2016, an additional lender was added to the facility. JPMorgan Chase Bank, N.A. serves as administrative agent for the syndicate of, now, 21 lenders, and no single lender has greater than a 7-percent share. The agreement permits each utility to individually borrow up to $750 million, subject to a combined limit of $1 billion for both utilities. It 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.

Borrowings bear interest at benchmark rates plus a margin that varies with the borrowing utility’s credit rating. The agreement requires each utility to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At September 30, 2016, the California Utilities were in compliance with this and all other financial covenants under the credit facility.

Each utility’s obligations under the agreement are individual obligations, and a default by one utility would not constitute a default by the other utility or preclude borrowings by, or the issuance of letters of credit on behalf of, the other utility.

At September 30, 2016, SDG&E had $54 million of commercial paper outstanding and SoCalGas had no outstanding borrowings supported by the facility. Available unused credit on the line at September 30, 2016 was $696 million and $750 million at SDG&E and SoCalGas, respectively, subject to the $1 billion maximum combined credit limit.

Sempra South American Utilities

Sempra South American Utilities has Peruvian Sol- and Chilean Peso-denominated credit facilities with a borrowing capacity of $506 million U.S. dollar equivalent. The credit facilities were entered into to finance working capital and for general corporate purposes. The Peruvian facilities require a debt to equity ratio of no more than 170 percent. At September 30, 2016, Sempra South American Utilities was in compliance with this financial covenant under the credit facilities. At September 30, 2016, Sempra South American Utilities had outstanding borrowings against the Peruvian facilities of $140 million, expiring between 2016 and 2019, bank guarantees of $16 million, and $236 million of available unused credit. There were no outstanding borrowings at September 30, 2016 under the $114 million Chilean facility.

Sempra Mexico

IEnova has a $600 million, five-year revolving credit agreement expiring in August 2020. The lenders are Banco Santander (México), S.A., Institución de Banca Múltiple, Grupo Financiero Santander México, Banco Nacional de Mexico, S.A. Integrante del Grupo Financiero Banamex, The Bank of Tokyo - Mitsubishi UFJ, LTD., The Bank of Nova Scotia and Sumitomo Mitsui Banking Corporation. At September 30, 2016, IEnova had $521 million of outstanding borrowings supported by the facility, and available unused credit on the line was $79 million.

WEIGHTED AVERAGE INTEREST RATES

The weighted average interest rates on the total short-term debt at Sempra Energy Consolidated were 1.19 percent and 1.09 percent at September 30, 2016 and December 31, 2015, respectively. The weighted average interest rates on total short-term debt at SDG&E were 1.06 percent and 1.01 percent at September 30, 2016 and December 31, 2015, respectively.

LONG-TERM DEBT

Sempra Energy

In October 2016, Sempra Energy publicly offered and sold $500 million of 1.625-percent, fixed-rate notes maturing in 2019. Sempra Energy used the proceeds from this offering to repay outstanding commercial paper.

SDG&E

In May 2016, SDG&E publicly offered and sold $500 million of 2.50-percent first mortgage bonds maturing in 2026. SDG&E used the proceeds from the offering to redeem, prior to a scheduled maturity in 2027, $105 million aggregate principal amount of 5-percent, tax-exempt industrial development revenue bonds, to repay outstanding commercial paper and for other general corporate purposes.

SoCalGas

In June 2016, SoCalGas publicly offered and sold $500 million of 2.60-percent first mortgage bonds maturing in 2026. SoCalGas used the proceeds from the offering to repay outstanding commercial paper and for other general corporate purposes.

Sempra South American Utilities

In July 2016, Luz del Sur publicly offered and sold $50 million of corporate bonds at 6.50 percent maturing in 2025.

Sempra Mexico

In September 2016, IEnova completed the acquisition of PEMEX’s 50-percent interest in GdC, as we discuss in Note 3. Pursuant to the agreement, IEnova assumed $364 million of long-term debt, of which $49 million is classified as current at September 30, 2016. Principal and interest payments are due quarterly each year, and the loan fully matures in December 2026. The loan bears interest equal to London Interbank Offered Rate (LIBOR) plus a spread of 2 percent to 2.75 percent, which varies over the term of the loan. To moderate exposure to interest rate and associated cash flow variability, GdC entered into floating-to-fixed interest rate swaps for the full loan amount, resulting in an all-in fixed rate of 2.63 percent plus the corresponding spread. The loan is collateralized by the TDF S. de R.L. de C.V. liquid petroleum gas pipeline and the San Fernando natural gas pipeline, which are wholly owned projects at GdC. The loan agreement contains various covenants, including maintaining a certain interest coverage ratio and a minimum members’ equity during the term of the loan. At September 30, 2016, GdC was in compliance with these financial covenants.

Sempra Natural Gas

In September 2016, Sempra Natural Gas completed the sale of EnergySouth, the parent company of Mobile Gas and Willmut Gas. Sempra Natural Gas received $318 million, net of $2 million cash sold, in cash proceeds and the buyer assumed debt of $67 million, which included $20 million of 4.14-percent first mortgage bonds and $42 million of 5-percent first mortgage bonds at Mobile Gas, and $5 million of 3.1-percent notes at Willmut Gas. We discuss the sale of EnergySouth in Note 3.

INTEREST RATE SWAPS

We discuss our fair value interest rate swaps and interest rate swaps to hedge cash flows in Note 7.

NOTE 7. 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 other comprehensive income (loss) (cash flow hedge), on the balance sheet (fair value hedges and regulatory offsets), or recognized in earnings. We classify cash flows from the settlements of 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 energy derivatives, both natural gas and electricity, 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 congestion revenue rights (CRRs), which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations.

•

Sempra Mexico, Sempra Natural Gas, and Sempra Renewables may use natural gas and electricity derivatives, as appropriate, to optimize the earnings of their assets which support the following businesses: liquefied natural gas (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 also uses natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its Mexican

distribution operations. These derivatives, which are 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.

We summarize net energy derivative volumes at September 30, 2016 and December 31, 2015 as follows:



NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
Segment and Commodity	Unit of measure	September 30, 2016	December 31, 2015
California Utilities:
SDG&E:
Natural gas	MMBtu(1)	56	70
Electricity	MWh(2)	4	1
Congestion revenue rights	MWh	46	36
SoCalGas – natural gas	MMBtu	2	1

Energy-Related Businesses:
Sempra Natural Gas – natural gas	MMBtu	35	43


(1)	Million British thermal units


(2)	Megawatt hours

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. We periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We 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.

Interest rate derivatives are utilized by the California Utilities as well as by other Sempra Energy subsidiaries and joint ventures. Interest rate derivatives are generally accounted for as hedges, and although the California Utilities generally recover borrowing costs in rates over time, the use of interest rate derivatives is subject to certain regulatory constraints, and the impact of interest rate derivatives may not be recovered from customers as timely as described above with regard to energy derivatives. 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 September 30, 2016 and December 31, 2015, the net notional amounts of our interest rate derivatives, excluding joint ventures, were:



INTEREST RATE DERIVATIVES
(Dollars in millions)
	September 30, 2016			December 31, 2015
	Notional debt		Maturities	Notional debt		Maturities
Sempra Energy Consolidated:
Cash flow hedges(1)(2)	$	753	2016-2028	$	384	2016-2028
Fair value hedges	—		—	300		2016
SDG&E:
Cash flow hedge(1)	307		2016-2019	315		2016-2019


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


(2)	At September 30, 2016, includes GdC, which was previously a joint venture and excluded from this table.

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. In January 2016 and September 2016, we entered into foreign currency derivatives with notional amounts totaling $550 million and $914 million, respectively.

At September 30, 2016 and December 31, 2015, the net notional amounts of our foreign currency derivatives, excluding joint ventures, were:



FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
	September 30, 2016			December 31, 2015
	Notional amount		Maturities	Notional amount		Maturities
Sempra Energy Consolidated:
Cross-currency swaps	$	408	2016-2023	$	408	2016-2023
Other foreign currency derivatives(1)	1,481		2016-2018	—		—


(1)	At September 30, 2016, includes GdC, which was previously a joint venture and excluded from this table.

In addition, Sempra South American Utilities uses foreign currency derivatives at its subsidiaries and joint ventures as a means 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.

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 September 30, 2016 and December 31, 2015, including the amount of cash collateral receivables that were not offset, as the cash collateral is in excess of liability positions.



DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	September 30, 2016
	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)	$	3		$	—		$	(20	)	$	(224	)
Commodity contracts not subject to rate recovery	—			—			(4		)	—
Derivatives not designated as hedging instruments:
Foreign exchange instruments	2			—			(25		)	—
Commodity contracts not subject to rate recovery	122			25			(128		)	(17		)
Associated offsetting commodity contracts	(114		)	(15		)	114			15
Associated offsetting cash collateral	—			(2		)	17			2
Commodity contracts subject to rate recovery	11			86			(59		)	(165		)
Associated offsetting commodity contracts	(5		)	(1		)	5			1
Associated offsetting cash collateral	—			—			12			17
Net amounts presented on the balance sheet	19			93			(88		)	(371		)
Additional cash collateral for commodity contracts not subject to rate recovery	15			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	19			—			—			—
Total(4)	$	53		$	93		$	(88	)	$	(371	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)	$	—		$	—		$	(13	)	$	(18	)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	8			86			(55		)	(165		)
Associated offsetting commodity contracts	(3		)	(1		)	3			1
Associated offsetting cash collateral	—			—			12			17
Net amounts presented on the balance sheet	5			85			(53		)	(165		)
Additional cash collateral for commodity contracts not subject to rate recovery	1			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	17			—			—			—
Total(4)	$	23		$	85		$	(53	)	$	(165	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$	3		$	—		$	(4	)	$	—
Associated offsetting commodity contracts	(2		)	—			2			—
Net amounts presented on the balance sheet	1			—			(2		)	—
Additional cash collateral for commodity contracts not subject to rate recovery	1			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	2			—			—			—
Total	$	4		$	—		$	(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.



DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31, 2015
	Current assets: Fixed-price contracts and other derivatives(1)			Other assets: Sundry			Current liabilities: Fixed-price contracts and other derivatives(2)			Deferred credits and other liabilities: Fixed-price contracts and other derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments(3)	$	4		$	1		$	(15	)	$	(156	)
Commodity contracts not subject to rate recovery	13			—			—			—
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery	245			32			(239		)	(21		)
Associated offsetting commodity contracts	(232		)	(20		)	232			20
Associated offsetting cash collateral	(6		)	—			4			—
Commodity contracts subject to rate recovery	28			49			(61		)	(64		)
Associated offsetting commodity contracts	(2		)	(2		)	2			2
Associated offsetting cash collateral	—			—			28			26
Net amounts presented on the balance sheet	50			60			(49		)	(193		)
Additional cash collateral for commodity contracts not subject to rate recovery	2			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	28			—			—			—
Total(4)	$	80		$	60		$	(49	)	$	(193	)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)	$	—		$	—		$	(14	)	$	(23	)
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery	—			—			(1		)	—
Associated offsetting cash collateral	—			—			1			—
Commodity contracts subject to rate recovery	27			49			(60		)	(64		)
Associated offsetting commodity contracts	(2		)	(2		)	2			2
Associated offsetting cash collateral	—			—			28			26
Net amounts presented on the balance sheet	25			47			(44		)	(59		)
Additional cash collateral for commodity contracts not subject to rate recovery	1			—			—			—
Additional cash collateral for commodity contracts subject to rate recovery	27			—			—			—
Total(4)	$	53		$	47		$	(44	)	$	(59	)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery	$	—		$	—		$	(1	)	$	—
Associated offsetting cash collateral	—			—			1			—
Commodity contracts subject to rate recovery	1			—			(1		)	—
Net amounts presented on the balance sheet	1			—			(1		)	—
Additional cash collateral for commodity contracts subject to rate recovery	1			—			—			—
Total	$	2		$	—		$	(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.

The effects of derivative instruments designated as hedges on the Condensed Consolidated Statements of Operations and in OCI and AOCI for the three months and nine months ended September 30 were:



FAIR VALUE HEDGE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Three months ended September 30,				Nine months ended September 30,
	Location	2016		2015		2016			2015
Sempra Energy Consolidated:
Interest rate instruments	Interest Expense	$	—	$	1	$	3		$	5
Interest rate instruments	Other Income, Net	—		—		(2		)	(2		)
Total(1)		$	—	$	1	$	1		$	3


(1)	There was no hedge ineffectiveness in either the three months or nine months ended September 30, 2016 or 2015. All other changes in the fair value of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and are recorded in Other Income, Net.



CASH FLOW HEDGE IMPACTS
(Dollars in millions)
	Pretax gain (loss) recognized in OCI							Pretax (loss) gain reclassified from AOCI into earnings
	Three months ended September 30,							Three months ended September 30,
	2016			2015			Location	2016			2015
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments(1)	$	(16	)	$	(10	)	Interest Expense	$	(4	)	$	(5	)
Interest rate instruments	17			(134		)	Equity Earnings, Before Income Tax	(3		)	(3		)
Interest rate and foreign exchange instruments	—			—			Remeasurement of Equity Method Investment	(7		)	—
Interest rate and foreign exchange instruments	13			—			Equity Earnings, Net of Income Tax	2			—
Commodity contracts not subject to rate recovery	2			6			Revenues: Energy- Related Businesses	—			3
Total(2)	$	16		$	(138	)		$	(12	)	$	(5	)
SDG&E:
Interest rate instruments(1)(2)	$	2		$	(4	)	Interest Expense	$	(3	)	$	(3	)
SoCalGas:
Interest rate instruments(2)	$	—		$	—		Interest Expense	$	(1	)	$	—

	Nine months ended September 30,							Nine months ended September 30,
	2016			2015			Location	2016			2015
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments(1)	$	(26	)	$	(22	)	Interest Expense	$	(11	)	$	(14	)
Interest rate instruments	(190		)	(123		)	Equity Earnings, Before Income Tax	(8		)	(9		)
Interest rate and foreign exchange instruments	—			—			Remeasurement of Equity Method Investment	(7		)	—
Interest rate and foreign exchange instruments	(20		)	—			Equity Earnings, Net of Income Tax	(4		)	—
Commodity contracts not subject to rate recovery	(2		)	6			Revenues: Energy- Related Businesses	7			10
Total(2)	$	(238	)	$	(139	)		$	(23	)	$	(13	)
SDG&E:
Interest rate instruments(1)(2)	$	(5	)	$	(9	)	Interest Expense	$	(9	)	$	(9	)
SoCalGas:
Interest rate instruments(2)	$	—		$	—		Interest Expense	$	(1	)	$	—


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


(2)	Amounts include negligible hedge ineffectiveness in the three months and nine months ended September 30, 2016 and 2015.

For Sempra Energy Consolidated, we expect that losses of $21 million, which are net of income tax benefit, that are currently recorded in AOCI (including $12 million in noncontrolling interests, substantially all of which is 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 negligible 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 September 30, 2016 is approximately 12 years and 3 years 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 19 years.

The effects of derivative instruments not designated as hedging instruments on the Condensed Consolidated Statements of Operations for the three months and nine months ended September 30 were:



UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
		Pretax (loss) gain on derivatives recognized in earnings
		Three months ended September 30,						Nine months ended September 30,
	Location	2016			2015			2016			2015
Sempra Energy Consolidated:
Foreign exchange instruments	Other Income, Net	$	(11	)	$	(4	)	$	(23	)	$	(7	)
Foreign exchange instruments	Equity Earnings, Net of Income Tax	1			(3		)	3			(4		)
Commodity contracts not subject to rate recovery	Revenues: Energy-Related Businesses	3			21			(26		)	33
Commodity contracts not subject to rate recovery	Operation and Maintenance	—			(2		)	1			(1		)
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	(118		)	(27		)	(90		)	(100		)
Commodity contracts subject to rate recovery	Cost of Natural Gas	—			—			(2		)	1
Total		$	(125	)	$	(15	)	$	(137	)	$	(78	)
SDG&E:
Commodity contracts subject to rate recovery	Operation and Maintenance	$	—		$	(1	)	$	—		$	(1	)
Commodity contracts subject to rate recovery	Cost of Electric Fuel and Purchased Power	(118		)	(27		)	(90		)	(100		)
Total		$	(118	)	$	(28	)	$	(90	)	$	(101	)
SoCalGas:
Commodity contracts not subject to rate recovery	Operation and Maintenance	$	—		$	(1	)	$	—		$	—
Commodity contracts subject to rate recovery	Cost of Natural Gas	—			—			(2		)	1
Total		$	—		$	(1	)	$	(2	)	$	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 is $6 million at each of September 30, 2016 and December 31, 2015. At September 30, 2016, if the credit ratings of Sempra Energy were reduced below investment grade, $8 million of additional assets could be required to be posted as collateral for these derivative contracts.

For SDG&E, the total fair value of this group of derivative instruments in a net liability position at September 30, 2016 and December 31, 2015 is $3 million and $5 million, respectively. At September 30, 2016, if the credit ratings of SDG&E were reduced below investment grade, $5 million 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 8. FAIR VALUE MEASUREMENTS

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

Recurring Fair Value Measures

The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at September 30, 2016 and December 31, 2015. 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 levels. We have not changed the valuation techniques or types of inputs we use to measure recurring fair values during the nine months ended September 30, 2016.

The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 7 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 September 30, 2016 and December 31, 2015 in the tables below include the following:

▪

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

▪

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


▪	Rabbi Trust investments include marketable securities that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1). These investments in marketable securities were negligible at both September 30, 2016 and December 31, 2015.

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



RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Fair value at September 30, 2016
	Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	607	$	—	$	—	$	—		$	607
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	48		52		—		—			100
Municipal bonds	—		161		—		—			161
Other securities	—		188		—		—			188
Total debt securities	48		401		—		—			449
Total nuclear decommissioning trusts(2)	655		401		—		—			1,056
Interest rate and foreign exchange instruments	—		5		—		—			5
Commodity contracts not subject to rate recovery	—		18		—		13			31
Commodity contracts subject to rate recovery	—		1		90		19			110
Total	$	655	$	425	$	90	$	32		$	1,202

Liabilities:
Interest rate and foreign exchange instruments	$	—	$	269	$	—	$	—		$	269
Commodity contracts not subject to rate recovery	19		1		—		(19		)	1
Commodity contracts subject to rate recovery	1		40		177		(29		)	189
Total	$	20	$	310	$	177	$	(48	)	$	459

	Fair value at December 31, 2015
	Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	619	$	—	$	—	$	—		$	619
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	47		44		—		—			91
Municipal bonds	—		156		—		—			156
Other securities	—		182		—		—			182
Total debt securities	47		382		—		—			429
Total nuclear decommissioning trusts(2)	666		382		—		—			1,048
Interest rate and foreign exchange instruments	—		5		—		—			5
Commodity contracts not subject to rate recovery	22		16		—		(4		)	34
Commodity contracts subject to rate recovery	—		1		72		28			101
Total	$	688	$	404	$	72	$	24		$	1,188

Liabilities:
Interest rate and foreign exchange instruments	$	—	$	171	$	—	$	—		$	171
Commodity contracts not subject to rate recovery	5		3		—		(4		)	4
Commodity contracts subject to rate recovery	—		68		53		(54		)	67
Total	$	5	$	242	$	53	$	(58	)	$	242


(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.


(2)	Excludes cash balances and cash equivalents.



RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
	Fair value at September 30, 2016
	Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	607	$	—	$	—	$	—		$	607
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	48		52		—		—			100
Municipal bonds	—		161		—		—			161
Other securities	—		188		—		—			188
Total debt securities	48		401		—		—			449
Total nuclear decommissioning trusts(2)	655		401		—		—			1,056
Commodity contracts not subject to rate recovery	—		—		—		1			1
Commodity contracts subject to rate recovery	—		—		90		17			107
Total	$	655	$	401	$	90	$	18		$	1,164

Liabilities:
Interest rate instruments	$	—	$	31	$	—	$	—		$	31
Commodity contracts subject to rate recovery	—		39		177		(29		)	187
Total	$	—	$	70	$	177	$	(29	)	$	218

	Fair value at December 31, 2015
	Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Nuclear decommissioning trusts:
Equity securities	$	619	$	—	$	—	$	—		$	619
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	47		44		—		—			91
Municipal bonds	—		156		—		—			156
Other securities	—		182		—		—			182
Total debt securities	47		382		—		—			429
Total nuclear decommissioning trusts(2)	666		382		—		—			1,048
Commodity contracts not subject to rate recovery	—		—		—		1			1
Commodity contracts subject to rate recovery	—		—		72		27			99
Total	$	666	$	382	$	72	$	28		$	1,148

Liabilities:
Interest rate instruments	$	—	$	37	$	—	$	—		$	37
Commodity contracts not subject to rate recovery	1		—		—		(1		)	—
Commodity contracts subject to rate recovery	—		67		53		(54		)	66
Total	$	1	$	104	$	53	$	(55	)	$	103


(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.


(2)	Excludes cash balances and cash equivalents.



RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
	Fair value at September 30, 2016
	Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Commodity contracts not subject to rate recovery	$	—	$	—	$	—	$	1		$	1
Commodity contracts subject to rate recovery	—		1		—		2			3
Total	$	—	$	1	$	—	$	3		$	4

Liabilities:
Commodity contracts subject to rate recovery	$	1	$	1	$	—	$	—		$	2
Total	$	1	$	1	$	—	$	—		$	2

	Fair value at December 31, 2015
	Level 1		Level 2		Level 3		Netting(1)			Total
Assets:
Commodity contracts subject to rate recovery	$	—	$	1	$	—	$	1		$	2
Total	$	—	$	1	$	—	$	1		$	2

Liabilities:
Commodity contracts not subject to rate recovery	$	1	$	—	$	—	$	(1	)	$	—
Commodity contracts subject to rate recovery	—		1		—		—			1
Total	$	1	$	1	$	—	$	(1	)	$	1


(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 congestion revenue rights (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
(Dollars in millions)
	Three months ended September 30,
	2016			2015
Balance as of July 1	$	24		$	42
Realized and unrealized losses	(145		)	(49		)
Settlements	34			43
Balance as of September 30	$	(87	)	$	36
Change in unrealized losses relating to
instruments still held at September 30	$	(114	)	$	(8	)



	Nine months ended September 30,
	2016			2015
Balance as of January 1	$	19		$	107
Realized and unrealized losses	(138		)	(103		)
Allocated transmission instruments	—			1
Settlements	32			31
Balance as of September 30	$	(87	)	$	36
Change in unrealized losses relating to
instruments still held at September 30	$	(111	)	$	(54	)

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 Independent System Operator (CAISO), an objective source. Annual auction prices are published once a year, typically in the middle of November, and remain in effect for the following year. The impact associated with discounting is negligible. Because 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. From January 1, 2016 to December 31, 2016, the auction prices range from $(24) per MWh to $10 per MWh at a given location, and from January 1, 2015 to December 31, 2015, the auction prices ranged from $(16) per MWh to $8 per MWh at a given location. 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 7.

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. At September 30, 2016, these electricity forward prices range from $19.20 per MWh to $58.50 per MWh. 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 7.

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 also do not affect earnings.

Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, temporary investments, accounts and notes receivable, current 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 September 30, 2016 and December 31, 2015:



FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
	September 30, 2016
	Carrying amount		Fair value
	Carrying amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Due from unconsolidated affiliates(1)	$	180	$	—	$	91	$	81	$	172
Total long-term debt(2)(3)	14,149		—		15,335		532		15,867
Preferred stock of subsidiary	20		—		26		—		26
SDG&E:
Total long-term debt(3)(4)	$	4,656	$	—	$	5,024	$	307	$	5,331
SoCalGas:
Total long-term debt(5)	$	3,009	$	—	$	3,323	$	—	$	3,323
Preferred stock	22		—		28		—		28

	December 31, 2015
	Carrying amount		Fair value
	Carrying amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Noncurrent due from unconsolidated affiliates(1)	$	175	$	—	$	97	$	69	$	166
Total long-term debt(2)(3)	13,761		—		13,985		648		14,633
Preferred stock of subsidiary	20		—		23		—		23
SDG&E:
Total long-term debt(3)(4)	$	4,304	$	—	$	4,355	$	315	$	4,670
SoCalGas:
Total long-term debt(5)	$	2,513	$	—	$	2,621	$	—	$	2,621
Preferred stock	22		—		25		—		25


(1)	Excluding accumulated interest outstanding of $15 million and $11 million at September 30, 2016 and December 31, 2015, respectively.

(2)

Before reductions for unamortized discount (net of premium) and debt issuance costs of $108 million and $107 million at September 30, 2016 and December 31, 2015, respectively, and excluding build-to-suit and capital lease obligations of $385 million and $387 million at September 30, 2016 and December 31, 2015, respectively. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.


(3)	Level 3 instruments include $307 million and $315 million at September 30, 2016 and December 31, 2015, respectively, related to Otay Mesa VIE.


(4)	Before reductions for unamortized discount and debt issuance costs of $46 million and $43 million at September 30, 2016 and December 31, 2015, respectively, and excluding capital lease obligations of $241 million and $244 million at September 30, 2016 and December 31, 2015, respectively.


(5)	Before reductions for unamortized discount and debt issuance costs of $27 million and $24 million at September 30, 2016 and December 31, 2015, respectively, and excluding capital lease obligations of $1 million at both September 30, 2016 and December 31, 2015, respectively.

We determine the fair value of certain noncurrent amounts due from unconsolidated affiliates, long-term debt and preferred stock based on a market approach using quoted market prices for identical or similar securities in thinly-traded markets (Level 2). We value other noncurrent amounts due from unconsolidated affiliates of Sempra South American Utilities using a perpetuity approach based on the obligation’s fixed interest rate, the absence of a stated maturity date and a discount rate reflecting local borrowing costs (Level 3). We value other long-term debt using an income approach based on the present value of estimated future cash flows discounted at rates available for similar securities (Level 3).

We provide the fair values for the securities held in the nuclear decommissioning trust funds related to the San Onofre Nuclear Generating Station (SONGS) in Note 9 below.

Non-Recurring Fair Value Measures – Sempra Energy Consolidated

Sempra Mexico

GdC. On September 26, 2016, IEnova completed the acquisition of PEMEX’s 50-percent interest in GdC, increasing its ownership interest to 100 percent. As a result of IEnova obtaining control over GdC, in the three months and nine months ended September 30, 2016, Sempra Mexico recognized a pretax gain of $617 million ($432 million after-tax) for the excess of the acquisition-date fair value of its previously held equity interest in GdC ($1.144 billion) over the carrying value of that interest ($520 million) and losses reclassified from AOCI ($7 million), included as Remeasurement of Equity Method Investment on Sempra Energy’s Condensed Consolidated Statements of Operations. The valuation technique used to measure the acquisition-date fair value of our equity interest in GDC immediately prior to the business acquisition was based on the fair value of the entire business combination ($2.288 billion) less the fair value of the consideration paid ($1.144 billion, the equity sale price). We considered use of the equity sale price to be a market participant input that is a Level 2 measurement in the fair value hierarchy. We discuss the GdC acquisition in Note 3.

TdM. In February 2016, management approved a plan to market and sell its TdM natural gas-fired power plant, and it was classified as held for sale on the Sempra Energy Condensed Consolidated Balance Sheet, as we discuss in Note 3. In September 2016, we received market information that indicated that the fair value of TdM may be less than its carrying value. As a result, after performing an analysis of the information, Sempra Mexico reduced the carrying value of TdM by recognizing a noncash impairment charge of $131 million ($111 million after-tax) in the three months and nine months ended September 30, 2016 in Impairment Losses on the Sempra Energy Condensed Consolidated Statements of Operations. Market values resulting from a third party bidding process are considered to be Level 2 inputs in the fair value hierarchy.

Sempra Natural Gas

Rockies Express. As we discuss in Note 3, in March 2016, Sempra Natural Gas agreed to sell its 25-percent interest in Rockies Express for cash consideration of $440 million, subject to adjustment at closing. The transaction closed in May 2016. In March 2016, we recorded a noncash impairment of our investment in Rockies Express of $44 million ($27 million after-tax). The charge is included in Equity Earnings, Before Income Tax, on the Sempra Energy Condensed Consolidated Statement of Operations for the nine months ended September 30, 2016. We considered the sale price for our equity interest in Rockies Express to be a market participants’ view of the total value of Rockies Express and measured the fair value of our investment based on the equity sale price. Use of this market participant input as the indicator of fair value is a Level 2 measurement in the fair value hierarchy.

The following table summarizes significant inputs impacting our non-recurring fair value measures:



NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Estimated fair value			Valuation technique	Fair value hierarchy	% of fair value measurement	Inputs used to develop measurement	Range of inputs
TdM	$	145	(1)	Market approach	Level 2	100%	Purchase price offers	100%
Investment in GdC	$	1,144	(2)	Market approach	Level 2	100%	Equity sale price	100%
Investment in Rockies Express	$	440	(3)	Market approach	Level 2	100%	Equity sale price	100%


(1)	At measurement date of September 29, 2016. At September 30, 2016, TdM has a carrying value of $146 million, reflecting subsequent business activity, and is classified as held for sale.


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


(3)	At measurement date of March 29, 2016. On May 9, 2016, Sempra Natural Gas sold its equity interest in Rockies Express.

NOTE 9. SAN ONOFRE NUCLEAR GENERATING STATION (SONGS)

SDG&E has a 20-percent ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which ceased operations in June 2013. On June 6, 2013, after an extended outage beginning in 2012, Southern California Edison Company (Edison), the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the Nuclear Regulatory Commission (NRC) to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC.

SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for financing its share of expenses and capital expenditures. SDG&E’s share of operating expenses is included in Sempra Energy’s and SDG&E’s Condensed Consolidated Statements of Operations.

SONGS Steam Generator Replacement Project

As part of the Steam Generator Replacement Project, 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 Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc. (collectively MHI). In July 2013, SDG&E filed a lawsuit against MHI seeking to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators. In October 2013,

Edison instituted binding arbitration proceedings against MHI seeking damages as well. SDG&E is participating in the arbitration as a claimant and respondent. The arbitration hearing concluded in April 2016, and a decision could come as early as this year. We discuss these proceedings in Note 11.

Settlement Agreement to Resolve the CPUC’s Order Instituting Investigation (OII) into the SONGS Outage (SONGS OII)

In November 2012, in response to the 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, including purchased replacement power costs, which are typically recovered through the Energy Resource Recovery Account (ERRA).

In April 2014, SDG&E filed with the CPUC in the SONGS OII proceeding a Settlement Agreement, along with Edison, The Utility Reform Network (TURN), the CPUC Office of Ratepayer Advocates (ORA) and two other intervenors who joined the Settlement Agreement (collectively, the Settling Parties).

In September 2014, the Settling Parties executed an Amended and Restated Settlement Agreement (Amended Settlement Agreement), which amended the Settlement Agreement, and in November 2014, the CPUC issued a final decision approving the Amended Settlement Agreement. The Amended Settlement Agreement does not affect on-going or future proceedings before the NRC, or litigation or arbitration related to potential future recoveries from third parties (except for the allocation to ratepayers of any recoveries as described below) or proceedings addressing decommissioning activities and costs. We discuss the terms of the Amended Settlement Agreement and related filings in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

In April 2015, a petition for modification (PFM) was filed with the CPUC by Alliance for Nuclear Responsibility (A4NR), an intervenor in the SONGS OII proceeding, asking the CPUC to set aside its decision approving the Amended Settlement Agreement and reopen the SONGS OII proceeding. In June 2015, TURN, a party to the Amended Settlement Agreement, filed a response supporting the A4NR petition. TURN does not question the merits of the Amended Settlement Agreement, but is concerned that certain allegations regarding Edison raised by A4NR have undermined the public’s confidence in the regulatory process. SDG&E has responded that TURN’s concerns regarding public perception do not impact the reasonableness of the Amended Settlement Agreement and are insufficient to overturn it.

In August 2015, ORA, also a party to the Amended Settlement Agreement, filed a PFM with the CPUC, withdrawing its support for the Amended Settlement Agreement and asking the CPUC to reopen the SONGS OII proceeding. The ORA does not question the merits of the Amended Settlement Agreement, but is concerned with the CPUC’s approach toward disclosures concerning Edison ex parte communications with the CPUC. SDG&E responded that the ORA’s PFM is insufficient to overturn the Amended Settlement Agreement, because the ORA fails to make a case that the Amended Settlement Agreement is no longer in the public interest.

In May 2016, the CPUC issued a 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 accordance with the ruling, Edison and SDG&E filed separate reports with the CPUC in June 2016 on the Amended Settlement Agreement and the status of its implementation, and filed separate legal briefs in July 2016 asserting that the Amended Settlement Agreement is reasonable and in the public interest.

Accounting and Financial Impacts

Through December 31, 2015 and September 30, 2016, the cumulative after-tax loss from plant closure recorded by Sempra Energy and SDG&E is $125 million, including a reduction in the after-tax loss of $13 million recorded in the first quarter of 2015. The remaining regulatory asset for the expected recovery of SONGS costs, consistent with the Amended Settlement Agreement, is $195 million ($45 million current and $150 million long-term) at September 30, 2016 and is recorded on the Condensed Consolidated Balance Sheets in Other Current Assets and Regulatory Assets Noncurrent, respectively, at Sempra Energy, and in Regulatory Assets Current and Other Regulatory Assets Noncurrent, respectively, at SDG&E. The amortization period prescribed for the regulatory asset is 10 years, which commenced in January 2015 following the CPUC’s final decision approving the Amended Settlement Agreement in November 2014.

Settlement with Nuclear Electric Insurance Limited (NEIL)

NEIL insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks. In October 2015, the SONGS co-owners (Edison, SDG&E and the City of Riverside) reached an agreement with NEIL to resolve all of SONGS’ insurance claims arising out of the failures of the replacement steam generators for a total payment by NEIL of $400 million, SDG&E’s share of which is $80 million. Pursuant to the terms of the SONGS OII Amended Settlement Agreement, after reimbursement of legal fees and a 5-percent allocation to shareholders, the net proceeds of $75 million were allocated to ratepayers through ERRA. We discuss NEIL further in Note 11.

Nuclear Decommissioning and Funding

As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison has begun the decommissioning phase of the plant. We discuss the process of decommissioning SONGS and oversight by the NRC in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

In accordance with state and federal requirements and regulations, SDG&E has assets held in trusts, referred to as the Nuclear Decommissioning Trusts (NDT), to fund decommissioning costs for SONGS Units 1, 2 and 3. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work will be done when Units 2 and 3 are decommissioned. At September 30, 2016, the fair value of SDG&E’s NDT assets was $1.1 billion. 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.

In April 2016, the CPUC adopted a decision approving a total decommissioning cost estimate for SONGS Units 2 and 3 of $4.411 billion (in 2014 dollars), of which SDG&E’s share is $899 million. The decision also approves an annual advice letter request process for SDG&E to request trust fund disbursements for decommissioning costs based on a forecast for 2016 and thereafter. Disbursements from the trust will then be made up to this annual forecast amount as decommissioning expenses are incurred. All disbursements will be subject to future refund until a reasonableness review of the actual decommissioning costs is conducted, which would be no less frequently than every three years.

SDG&E has received authorization from the CPUC to access trust funds for SONGS decommissioning costs of up to $218 million for 2013 through 2016 (forecasted). The total of $218 million includes $37 million authorized for withdrawal that is pending satisfactory clarification by final settlement of unresolved spent fuel storage costs with the U.S. Department of Energy (DOE) or clarification by the Internal Revenue Service (IRS) that certain spent fuel costs and other costs are eligible decommissioning costs, payable from qualified nuclear decommissioning trusts. We are uncertain as to when such settlement or clarification will be obtained.

We discuss the NDT and matters related to its funding and the funding of decommissioning costs by the NDT further in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report. We discuss matters related to spent nuclear fuel in Note 11.

Nuclear Decommissioning Trusts

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 trusts are invested in accordance with CPUC regulations. These trusts are presented on the Sempra Energy and SDG&E Condensed Consolidated Balance Sheets at fair value with the offsetting credits recorded in Regulatory Liabilities Arising from Removal Obligations.

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 8.



NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value
At September 30, 2016:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies(1)	$	95	$	5	$	—		$	100
Municipal bonds(2)	150		11		—			161
Other securities(2)	183		9		(4		)	188
Total debt securities	428		25		(4		)	449
Equity securities	188		422		(3		)	607
Cash and cash equivalents	12		—		—			12
Total	$	628	$	447	$	(7	)	$	1,068
At December 31, 2015:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies	$	89	$	2	$	—		$	91
Municipal bonds	148		8		—			156
Other securities	194		1		(13		)	182
Total debt securities	431		11		(13		)	429
Equity securities	214		412		(7		)	619
Cash and cash equivalents	15		—		—			15
Total	$	660	$	423	$	(20	)	$	1,063


(1)	Maturity dates are 2017-2065.


(2)	Maturity dates are 2016-2115.

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
(Dollars in millions)
	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
Proceeds from sales(1)	$	282		$	210		$	486		$	431
Gross realized gains	24			18			32			24
Gross realized losses	(3		)	(6		)	(14		)	(13		)


(1)	Excludes securities that are held to maturity.

Net unrealized gains (losses) are included in Regulatory Liabilities Arising from Removal Obligations 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.

NOTE 10. CALIFORNIA UTILITIES’ REGULATORY MATTERS

We discuss regulatory matters affecting our California Utilities in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and provide updates to those discussions and details of any new matters below.

JOINT MATTERS

CPUC General Rate Case (GRC)

The CPUC uses a general rate case proceeding to set sufficient rates to allow the California Utilities to recover their reasonable cost of operations and maintenance and to provide the opportunity to realize their authorized rates of return on their investment.

The California Utilities filed their 2016 General Rate Case (2016 GRC) applications in November 2014. In September 2015, the California Utilities filed settlement agreements with the CPUC to resolve all material matters related to the proceeding, except for the revenue requirement implications of certain income tax benefits associated with flow-through tax repair deductions, discussed below. The settlement agreements were with eight of eleven intervening parties.

In June 2016, the CPUC issued a final decision in the 2016 GRC. The final decision (2016 GRC FD) adopts substantially all of the terms of the settlement agreements entered into between SDG&E and SoCalGas and eight of the eleven intervening parties in the 2016 GRC. The 2016 GRC FD adopts two revenue requirement changes, the first of which, relating to the extension of bonus depreciation, is the only significant change to the settlement agreements. The second revenue requirement adjustment relates to income tax benefits associated with flow-through repair deductions (the settling parties did not reach agreement on this second matter). With these adjustments, the final decision adopts a 2016 revenue requirement of $1.791 billion for SDG&E, which is $20 million less than the $1.811 billion proposed in the settlement agreements. For SoCalGas, the final decision’s adjustments result in a 2016 revenue requirement of $2.204 billion, which is $15 million less than the $2.219 billion proposed in the settlement agreements. The 2016 GRC FD also requires certain refunds to be paid to customers and establishes a two-way income tax expense memorandum account, each discussed below.

Consistent with the settlement agreements, the 2016 GRC FD adopts subsequent annual escalation of the adopted revenue requirements by 3.5 percent for years 2017 and 2018 and continuation of the Z-Factor mechanism for qualifying cost recovery. The Z-Factor mechanism allows the California Utilities to seek cost recovery of significant cost increases, under certain unforeseen circumstances, incurred between GRC filings, subject to a $5 million deductible per event. Also, the 2016 GRC FD denies a separate agreement between the ORA and the California Utilities requesting a four-year GRC period and instead adopts a three-year GRC period (through 2018).

The California Utilities recorded revenues in the first quarter of 2016 based on levels authorized for 2015 under the 2012 GRC, because a final decision in the 2016 GRC was not issued by March 31, 2016. The 2016 GRC FD is effective retroactive to January 1, 2016, and the California Utilities recorded the retroactive impacts in the second quarter of 2016. For SoCalGas and SDG&E, these amounts include an incremental after-tax earnings impact of $12 million and $9 million, respectively, related to the first quarter of 2016. The adopted revenue requirements associated with the seven-month period through July 2016 will be recovered in rates over a 17-month period, beginning August 2016. At September 30, 2016, SoCalGas is reporting on its Condensed Balance Sheet a regulatory asset of $58 million, with $12 million as noncurrent, representing retroactive revenue from the 2016 GRC FD from January 1 through June 30, 2016 to be recovered in rates through December 2017. At September 30, 2016, SDG&E is reporting on its Condensed Consolidated Balance Sheet a regulatory asset of $25 million, with $5 million as noncurrent, representing retroactive revenue from the 2016 GRC FD from January 1 through June 30, 2016 to be recovered in rates through December 2017.

The 2016 GRC FD results in certain accounting impacts associated with the income tax repairs deduction matter. In general, the 2016 GRC FD considers that the income tax benefits obtained from income tax repairs deductions exceeded amounts forecasted by the California Utilities from 2011 to 2015, and that they were attributed to shareholders during that time. The 2016 GRC FD reallocates the economic benefit of this tax deduction forecasting difference to ratepayers. Accordingly, revenues corresponding to income tax repair deductions that exceeded forecasted amounts relating to 2015, which have been tracked in memorandum accounts, are ordered to be refunded to customers. The 2015 estimated amounts in the memorandum accounts totaled $72 million for SoCalGas and $37 million for SDG&E. Pursuant to this refund requirement, SoCalGas and SDG&E recorded regulatory liabilities for these amounts, resulting in after-tax charges to earnings of $43 million and $22 million, respectively, in the second quarter of 2016 (summarized below). In addition, the 2016 GRC FD reduced rate base by $38 million at SoCalGas and $55 million at SDG&E. The corresponding reductions in the 2016 revenue requirement will be $5 million at SoCalGas and $7 million at SDG&E (which reductions are included in the adopted 2016 revenue requirement amounts described above). The rate base reductions reallocate to ratepayers the economic benefits associated with tax repair deductions that were previously provided to the shareholders for the period of 2012-2014 for

SoCalGas and 2011-2014 for SDG&E. The rate base reductions do not result in an impairment of any of our reported assets, but will impact our revenues and earnings prospectively.

The 2016 GRC FD also requires us to notify the CPUC if the 2012-2015 repairs deductions estimated in this GRC are different from the actual repairs deductions for SDG&E and SoCalGas. SoCalGas and SDG&E recorded regulatory liabilities of $11 million and $15 million, respectively, related to 2012-2014, resulting in after-tax charges to earnings for these differences of $6 million and $9 million in the second quarter of 2016 for SoCalGas and SDG&E, respectively (summarized below). In the third quarter of 2016, SDG&E and SoCalGas completed their 2015 calendar year tax returns, and final tax deductions associated with tax repair benefits to be refunded to ratepayers associated with the 2015 memo account are lower than the amounts estimated in 2015. Accordingly, the amounts to be refunded decreased by $5 million for SDG&E and $19 million for SoCalGas. In October 2016, SDG&E and SoCalGas filed a regulatory account update with the CPUC to reflect their final total 2015 repair allowance deductions of $32 million and $53 million, respectively. After recording the related income tax effect and corresponding regulatory revenue adjustments for income tax purposes, there was no net impact to earnings from the adjustments to the 2015 tax repairs deductions recorded in the third quarter of 2016. Accordingly, the earnings impacts in the table below are also the impacts in the nine months ended September 30, 2016.

Following is a summary of immediate earnings impacts from the 2016 GRC FD recorded in the second quarter of 2016:



EARNINGS IMPACTS FROM THE 2016 GRC FD RECORDED IN THE SECOND QUARTER OF 2016
(Dollars in millions)
	SoCalGas						SDG&E
	Pretax earnings (charge)			After-tax earnings (charge)			Pretax earnings (charge)			After-tax earnings (charge)
Retroactive revenue requirement increase
for the first quarter of 2016	$	20		$	12		$	15		$	9
Adjustments to revenue related to tax
repairs deductions:
2015 memorandum account balance	$	(72	)	$	(43	)	$	(37	)	$	(22	)
True-up of 2012-2014 estimates to actuals	(11		)	(6		)	(15		)	(9		)
Total	$	(83	)	$	(49	)	$	(52	)	$	(31	)

In July 2016, SDG&E, SoCalGas and the parties to the settlement agreements filed a joint motion indicating their agreement to accept the CPUC’s adjustments to the original settlements with one additional change. The settlement parties agree that SDG&E and SoCalGas will retain the right to seek further review and modification of the bonus depreciation adjustment made by the CPUC, so that SDG&E and/or SoCalGas can pursue relief in the form of full or partial restoration of the total revenue requirements reflected in the original settlement agreements. We expect CPUC action on the joint motion in 2016 or 2017.

Finally, the 2016 GRC FD requires the establishment of a two-way income tax expense memorandum account to track any revenue differences resulting from differences between the income tax expense forecasted in the GRC and the income tax expense incurred by the California Utilities from 2016 through 2018. The differences tracked are to specifically include tax expense differences relating to


▪	net revenue changes;


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


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

The account will remain open, and the balance in the account will be reviewed in subsequent GRC proceedings, until the CPUC decides to close the account. In July 2016, to address the implementation of the 2016 GRC FD, the California Utilities filed an advice letter to establish a two-way memorandum account to track revenue requirement differences resulting from the differences in the income tax expense forecasted in the GRC proceedings of SDG&E and SoCalGas and the income tax expense incurred by them during the GRC period. Starting in the second quarter of 2016, SoCalGas and SDG&E are recording liabilities associated with tracking the differences in the income tax expense forecasted in the GRC proceedings and the income tax expense incurred, which for the three months and nine months ended September 30, 2016 resulted in after-tax charges to earnings of $2 million ($4 million pretax) and $11 million ($19 million pretax), respectively, for SoCalGas and negligible amounts for SDG&E.

Natural Gas Pipeline Operations Safety Assessments

In June 2014, the CPUC issued a final decision addressing SDG&E’s and SoCalGas’ Pipeline Safety Enhancement Plan (PSEP). Specifically, the decision determined the following for Phase 1 of the program:


▪	approved the utilities’ model for implementing PSEP;


▪	approved a process, including a reasonableness review, to determine the amount that the utilities will be authorized to recover from ratepayers for the interim costs incurred through the date of the final decision to implement PSEP, which is recorded in regulatory accounts authorized by the CPUC;


▪	approved balancing account treatment, subject to a reasonableness review, for incremental costs yet to be incurred to implement PSEP; and


▪	established the criteria to determine the amounts that would not be eligible for cost recovery, including:


◦	certain costs incurred or to be incurred searching for pipeline test records,


◦	the cost of pressure testing pipelines installed after July 1, 1961 for which the company has not found sufficient records of testing, and


◦	any undepreciated balances for pipelines installed after 1961 that were replaced due to insufficient documentation of pressure testing.

As a result of this decision, SoCalGas recorded an after-tax earnings charge of $5 million in 2014 for costs incurred in prior periods that were no longer subject to recovery. After taking the amounts disallowed for recovery into consideration, as of September 30, 2016, SDG&E and SoCalGas have recorded PSEP costs of $18 million and $212 million, respectively, in the CPUC-authorized regulatory account.

In July 2014, the ORA and TURN filed a joint application for rehearing of the CPUC’s June 2014 final decision. In March 2015, the CPUC issued a decision denying the ORA’s and TURN’s second request for rehearing, but keeping the record open to admit additional evidence on the limited issue of pressure testing or replacing pipelines installed between January 1, 1956 and July 1, 1961. The ORA and TURN allege that the CPUC made a legal error in directing that ratepayers, not shareholders, be responsible for the costs associated with testing or replacing transmission pipelines that were installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. In December 2015, the CPUC issued a final decision finding that ratepayers should not bear the costs associated with pressure testing subject pipelines, or, if replaced, ratepayers should bear neither the average cost of pressure testing nor the undepreciated balance of abandoned pipelines. In January 2016, SoCalGas and SDG&E jointly filed a request with the CPUC seeking rehearing of its December 2015 decision. In May 2016, the CPUC issued a decision denying the request for rehearing. Through September 30, 2016, the after-tax disallowed costs for SoCalGas and SDG&E are $3.6 million and $0.5 million, respectively.

In October 2014, SDG&E and SoCalGas filed a petition with the CPUC requesting authority to begin to recover PSEP costs from customers in the year in which the costs are incurred, subject to refund pending the results of a reasonableness review by the CPUC, instead of recovery of such costs in a subsequent year.

In August 2016, the CPUC issued a final decision authorizing SoCalGas and SDG&E to recover, subject to refund pending reasonableness reviews, the revenue requirements associated with 50 percent of their incurred PSEP Phase 1 costs recorded to regulatory accounts; file two reasonableness review applications for Phase 1 projects completed through 2017; file a Phase 2 revenue requirement forecast application for costs to be incurred in 2017 and 2018; and include in their 2019 GRC applications, and any future GRCs, all other PSEP costs not the subject of prior applications.

In December 2014, SDG&E and SoCalGas filed an application with the CPUC for recovery of $0.1 million and $46 million, respectively, in costs recorded in the regulatory account through June 11, 2014. In June 2015, SDG&E and SoCalGas agreed to remove certain projects from the filing and defer their review to future proceedings when the projects are fully completed. The ORA, TURN and the Southern California Generation Coalition (SCGC) have recommended disallowances related to completed projects, as well as facilities build-out costs, de-scoped projects, and project management and consulting costs. The CPUC issued a proposed decision in September 2016, revised in October 2016, finding the costs associated with completed projects reasonable and approving $0.1 million and $33.1 million of the total costs requested by SDG&E and SoCalGas, respectively. The proposed decision does not approve approximately $2 million in insurance-related costs, but allows SDG&E and SoCalGas to seek recovery at a later date. A final decision is expected in the fourth quarter of 2016.

In September 2016, SoCalGas and SDG&E filed a joint application with the CPUC for reasonableness review and rate recovery of costs of certain pipeline safety projects completed by June 30, 2015 and recorded in their authorized regulatory accounts. The total costs submitted for review are $180.5 million for SoCalGas and $14.9 million for SDG&E. SoCalGas and SDG&E expect a decision from the CPUC in 2017.

SDG&E MATTERS

Wildfire Claims Cost Recovery

In September 2015, SDG&E filed an application with the CPUC requesting rate recovery of an estimated $379 million in costs related to the October 2007 wildfires that have been recorded to the Wildfire Expense Memorandum Account (WEMA). These costs represent

a portion of the estimated total of $2.4 billion in costs and legal fees that SDG&E has incurred to resolve third-party damage claims arising from the October 2007 wildfires. The requested amount of $379 million is the net estimated cost incurred by SDG&E after deductions for insurance reimbursement ($1.1 billion), third party settlement recoveries ($824 million) and allocations to FERC-jurisdictional rates ($80 million), and reflects a voluntary 10 percent shareholder contribution applied to the net WEMA balance ($42 million). SDG&E requested a CPUC decision by the end of 2016 and is proposing to recover the costs in rates over a six- to ten-year period. In April 2016, the CPUC issued a ruling establishing the scope and schedule for the proceeding, which will be managed in two phases. Phase 1 will address SDG&E’s operational and management prudence surrounding the 2007 wildfires. Phase 2 will address whether SDG&E’s actions and decision-making in connection with settling legal claims in relation to the wildfires were reasonable. In October 2016, intervening parties submitted Phase 1 testimony raising various concerns with SDG&E’s operations and management prior to and during the 2007 wildfires. Participating parties asked that the CPUC reject SDG&E’s request for cost recovery. Evidentiary hearings in Phase 1 are scheduled to be held in January 2017, with a final decision scheduled to be issued in the second half of 2017. The procedural schedule for Phase 2 will be determined after Phase 1 is concluded.

In September 2015, the presiding judge assigned by the FERC to SDG&E’s annual Electric Transmission Formula Rate filing (TO4 Formula Cycle 2) issued an initial decision and an order on summary judgment that authorized SDG&E to recover all of the costs incurred and allocated to SDG&E’s FERC-regulated operations, including $23.1 million of costs associated with the 2007 wildfires. In October 2015, the CPUC filed a request for rehearing of the FERC’s September 2015 order, which requested abeyance of SDG&E’s request to recover 2007 wildfire damage expenses. In April 2016, the FERC affirmed its findings in the September 2015 order and denied the CPUC’s request for rehearing. The FERC decision finalizes SDG&E’s base transmission revenue requirement and the recovery of $23.1 million of wildfire damage expenses allocated to SDG&E’s FERC-regulated operations.

We provide additional information about wildfire litigation costs and their recovery in Note 11.

SONGS

We discuss regulatory and other matters related to SONGS in Note 9.

SOCALGAS MATTERS

Aliso Canyon Turbine Replacement Project

In September 2016, SoCalGas received a citation from the CPUC alleging non-compliance with environmental mitigation measures outlined in the final environmental impact report for the Aliso Canyon Turbine Replacement Project. In particular, the allegations assert that SoCalGas failed to properly implement and maintain mitigation measures prescribed in the project’s Storm Water Pollution Prevention Plan, which is designed primarily to protect overall water quality and to minimize erosion and sedimentation during construction. Additionally, the CPUC alleges that SoCalGas crews repeatedly encroached upon a nesting bird buffer zone during construction. As a result of procedural matters, the CPUC re-issued the citation on October 26, 2016. The fines associated with the citation are approximately $700,000. SoCalGas is in the process of evaluating the citation and its options in response to the citation.

Aliso Canyon Natural Gas Storage Facility

We discuss various regulatory matters regarding the Aliso Canyon natural gas storage facility and leak in Note 11.

Natural Gas Procurement

In June 2016, SoCalGas filed an application for a gas cost incentive mechanism award of $5 million for natural gas procured for its core customers during the 12-month period ended March 31, 2016. The CPUC’s current schedule calls for a decision in the first half of 2017.

CALIFORNIA UTILITIES — MAJOR PROJECTS

We discuss the California Utilities’ major projects in detail in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and provide updates to those discussions and details in the tables below.



MAJOR PROJECTS – UPDATES

Joint Utilities Projects
Southern Gas System Reliability Project (North-South Pipeline)


▪	In July 2016, the CPUC issued a final decision which denies the California Utilities’ request for a permit to construct.

▪

In June 2016, SoCalGas recorded an after-tax impairment charge of $13 million for the development costs it had invested in the project. The pretax charge of $22 million is included in Impairment Losses on Sempra Energy’s and SoCalGas’ Condensed Consolidated Statements of Operations for the nine months ended September 30, 2016. We expect to make a filing to the CPUC seeking recovery of all or a portion of these costs.



Pipeline Safety & Reliability Project

▪

SDG&E and SoCalGas filed an amended application with the CPUC in March 2016 providing detailed analysis and testimony supporting the proposed project. The revised request also presents additional information on the costs and benefits of project alternatives, safety evaluation and compliance analysis, and statutory and procedural requirements. SDG&E and SoCalGas seek approval to construct the proposed project, estimated at a cost of $633 million, and authority to recover the associated revenue requirement in rates.




SDG&E Projects
Cleveland National Forest (CNF) Transmission Projects


▪	In May 2016, the CPUC issued a final decision granting SDG&E a permit to construct. The project will be installed at an estimated cost of $680 million: $470 million for the various transmission-level facilities and $210 million for associated distribution-level facilities, including distribution circuits and additional undergrounding required by the final environmental impact statement.


▪	In July 2016, the Cleveland National Forest Foundation and the Protect Our Communities Foundation filed a joint application for rehearing of the final decision.



Sycamore-Peñasquitos Transmission Project


▪	In October 2016, the CPUC issued a final decision granting SDG&E a Certificate of Public Convenience and Necessity (CPCN) to construct the project, with a cost cap of $260 million.



South Orange County Reliability Enhancement

▪

CPUC issued its final environmental impact report (EIR) for the project in April 2016. The EIR concluded that an alternative project is considered environmentally superior to SDG&E’s proposal. The final EIR states that the CPUC is not required to adopt the environmentally superior alternative if there are overriding considerations in favor of another alternative. The CPUC will consider the findings in determining whether to approve SDG&E’s proposed project or an alternative to it.

▪

In September 2016, draft and alternate decisions were issued by the Administrative Law Judge (ALJ) and Assigned Commissioner. The ALJ decision rejects SDG&E’s proposed project and grants a CPCN to construct the project identified as environmentally superior in the final EIR. The Assigned Commissioner decision determines that the environmentally superior project is infeasible and, given overriding considerations, grants SDG&E a CPCN to construct its proposed project with a project cost cap of $381 million.


▪	Final CPUC decision expected in fourth quarter of 2016.



Energy Storage Projects


▪	In August 2016, the CPUC approved SDG&E’s request to own and operate two energy storage projects totaling 37.5 MW. The purpose of the two projects is to enhance electric reliability in the San Diego service territory.


▪	Expected completion in the first quarter of 2017.

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 September 30, 2016, Sempra Energy’s accrued liabilities for legal proceedings, including associated legal fees and costs of litigation, on a consolidated basis, were $23 million. At September 30, 2016, accrued liabilities for legal proceedings were $21 million for SDG&E and $1 million for SoCalGas. Amounts for Sempra Energy and SoCalGas include $1 million for matters related to the Aliso Canyon natural gas leak, which we discuss below.

SDG&E

2007 Wildfire Litigation

In October 2007, San Diego County experienced several catastrophic wildfires. Reports issued by the California Department of Forestry and Fire Protection (Cal Fire) concluded that two of these fires (the Witch and Rice fires) were SDG&E “power line caused” and that a third fire (the Guejito fire) occurred when a wire securing a Cox Communications’ (Cox) fiber optic cable came into contact with an SDG&E power line “causing an arc and starting the fire.” A September 2008 staff report issued by the CPUC’s Consumer Protection and Safety Division, now known as the Safety and Enforcement Division, reached substantially the same conclusions as the Cal Fire reports, but also contended that the power lines involved in the Witch and Rice fires and the lashing wire involved in the Guejito fire were not properly designed, constructed and maintained.

Numerous parties sued SDG&E and Sempra Energy in San Diego County Superior Court seeking recovery of unspecified amounts of damages, including punitive damages, from the three fires. They asserted various bases for recovery, including inverse condemnation based upon a California Court of Appeal decision finding that another California investor-owned utility was subject to strict liability, without regard to foreseeability or negligence, for property damages resulting from a wildfire ignited by power lines. SDG&E has resolved almost all of these lawsuits. One Superior Court case remains in which the plaintiff is challenging the dismissal of her lawsuit and an appeal is likely. Only one appeal 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 establishes reserves for the wildfire litigation as information becomes available and amounts are estimable.

SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of the costs incurred to resolve wildfire claims in excess of its liability insurance coverage and the amounts recovered from third parties. Accordingly, at September 30, 2016, Sempra Energy and SDG&E have recorded assets of $356 million in Other Regulatory Assets (long-term) on their Condensed Consolidated Balance Sheets, including $354 million related to CPUC-regulated operations, which represents the amount substantially equal to the aggregate amount it has paid and reserved for payment for the resolution of wildfire claims and related costs in excess of its liability insurance coverage and amounts recovered from third parties. On September 25, 2015, SDG&E filed an application with the CPUC seeking authority to recover these costs, as we discuss in Note 10. Should SDG&E conclude that recovery in rates is no longer probable, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated at September 30, 2016, the resulting after-tax charge against earnings would have been up to approximately $210 million. A failure to obtain substantial or full recovery of these costs from customers, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s results of operations and cash flows.

We provide additional information about excess wildfire claims cost recovery and related CPUC actions in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report and discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Smart Meters Patent Infringement Lawsuit

In October 2011, SDG&E was sued by a Texas design and manufacturing company in Federal District Court, Southern District of California, and later transferred to the Federal District Court, Western District of Oklahoma as part of Multi-District Litigation (MDL) proceedings, alleging that SDG&E’s recently installed smart meters infringed certain patents. The meters were purchased from a third party vendor that has agreed to defend and indemnify SDG&E. The lawsuit sought injunctive relief and recovery of unspecified amounts of damages. The third party vendor has settled the lawsuit without cost to SDG&E, and a dismissal was entered in federal court on July 20, 2016.

Lawsuit Against Mitsubishi Heavy Industries, Ltd.

On July 18, 2013, SDG&E filed a lawsuit in the Superior Court of California in the County of San Diego against Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc. (collectively MHI). The lawsuit seeks to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators MHI provided to the SONGS nuclear power plant. The lawsuit asserts a number of causes of action, including fraud, based on the representations MHI made about its qualifications and ability to design generators free from defects of the kind that resulted in the permanent shutdown of the plant and further seeks to set aside the contractual limitation of damages that MHI has asserted. On July 24, 2013, MHI removed the lawsuit to the United States District Court for the Southern District of California and on August 8, 2013, MHI moved to stay the proceeding pending resolution of the dispute resolution process involving MHI and Edison arising from their contract for the purchase and sale of the steam generators. On October 16, 2013, Edison initiated an arbitration proceeding against MHI seeking damages stemming from the failure of the replacement steam generators. In late December 2013, MHI answered and filed a counterclaim against Edison. On March 14, 2014, MHI’s motion to stay the United States District Court proceeding was granted with instructions that require the parties to allow SDG&E to participate in the ongoing Edison/MHI arbitration. As a result, SDG&E participated in the arbitration as a claimant and respondent. The arbitration hearing concluded at the end of April 2016, and a decision could come as early as this year.

Rim Rock Wind Farm

In 2011, the CPUC and FERC approved SDG&E’s estimated $285 million tax equity investment in a wind farm project and its purchase of renewable energy credits from that project. SDG&E’s contractual obligations to both invest in the Rim Rock wind farm and to purchase renewable energy credits from the wind farm under the power purchase agreement were subject to the satisfaction of certain conditions which, if not achieved, would allow SDG&E to terminate the power purchase agreement and not make the investment.

In December 2013, SDG&E and the project developer began litigating claims against each other regarding whether the project developer had timely satisfied all contractual conditions necessary to trigger SDG&E’s obligations to invest in the project and purchase renewable energy credits. On February 11, 2016, SDG&E, the project developer and several of the project developer’s parent and affiliated entities entered into a settlement agreement, which was approved by the CPUC in July 2016 and all related lawsuits were dismissed. Under the settlement agreement, among other things, the parties agreed to terminate the tax equity investment arrangement, continue the power purchase agreement for the wind farm generation and release all claims against each other, while generally continuing the other elements of the 2011 approved decision. The settlement agreement will result in a $39 million credit to ratepayers.

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, located in the northern part of the San Fernando Valley in Los Angeles County. The Aliso Canyon facility has been operated by SoCalGas since 1972. SS25 is more than one mile away from and 1,200 feet above the closest homes. It is one of more than 100 injection and withdrawal wells at the storage facility.

Stopping the Leak, and Local Community Mitigation Efforts. SoCalGas worked closely with several of the world’s leading experts to stop the leak, including planning and obtaining all necessary approvals for drilling relief wells. On February 18, 2016, the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR) confirmed that the well was permanently sealed.

risk and that it was safe for residents to return home, the Superior Court issued an order on May 20, 2016, as supplemented by the Superior Court on May 25, 2016, ruling that: (1) currently relocated residents be given the choice to request residence cleaning, to be performed according to the DPH’s proposed protocol and at SoCalGas’ expense, and (2) the relocation program for currently relocated residents would terminate. SoCalGas completed the cleaning program, and the relocation program ended July 24, 2016.

Apart from the Superior Court order, on May 13, 2016, the DPH also issued a directive that SoCalGas 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 have experienced symptoms from the natural gas leak (the Directive). SoCalGas contends that the Directive is invalid and unenforceable and has filed a petition for writ of mandate to set aside the Directive.

The total 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.

Cost Estimates and Accounting Impact. As of September 30, 2016, SoCalGas recorded estimated costs of $763 million related to the leak. Of this amount, approximately 70 percent is for the temporary relocation program (including cleaning costs and certain labor costs) and approximately 20 percent is 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 to determine the cause of the leak. The remaining portion of the $763 million includes legal costs incurred to defend litigation, the value of lost gas, the costs to mitigate the actual natural gas released, and other costs. As the value of lost gas reflects the current replacement cost, the value may fluctuate until such time as replacement gas is purchased and injected into storage. SoCalGas made a commitment in December 2015 to mitigate the actual natural gas released and has been working on a plan to accomplish the mitigation. SoCalGas adjusts its estimated total liability associated with the leak as additional information becomes available. During the third quarter of 2016, the increase in the estimated costs of $46 million was primarily based on the increased scope and duration of the root cause analysis effort, which is controlled by DOGGR, as well as the claims recovery process associated with the relocation program. The $763 million represents management’s best estimate of these costs related to the leak. Of these costs, a substantial portion has been paid and $73 million is recorded as Reserve for Aliso Canyon Costs as of September 30, 2016 on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets for amounts expected to be paid after September 30, 2016.

As of September 30, 2016, we recorded the expected recovery of the costs described in the immediately preceding paragraph related to the leak of $664 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 $94 million of insurance proceeds we received in the second and third quarters of 2016 related to control of well expenses 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 would have a material adverse effect on SoCalGas’ and Sempra Energy’s financial condition, results of operations and cash flows.

The above amounts do not include any unsettled damage awards, restitution, or any civil, administrative or criminal fines, costs or other penalties that may be imposed, as it is not possible to predict the outcome of any criminal or civil proceeding or any administrative action in which such damage awards, restitution or civil or criminal fines, costs or other penalties could be imposed, and any such amounts, if awarded or imposed, cannot be reasonably estimated at this time. In addition, the above amounts do not include the cost to clean additional homes pursuant to the DPH 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.

In March 2016, the CPUC issued a decision directing 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 gas storage field. The CPUC will determine at a later time whether, and to what extent, the tracked revenues may be refunded to ratepayers. Pursuant to the CPUC’s decision, SoCalGas filed an advice letter requesting to establish a memorandum account to track all business-as-usual costs to own and operate the Aliso Canyon storage field, which has been protested by intervening parties. In July 2016, SoCalGas filed a supplemental advice letter that replaced the term “actual costs” with “normal, business as usual” before each reference to costs. In September 2016, the supplemental filing was approved and made effective as of March 17, 2016, the date of the decision directing the establishment of the account.

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. In reviewing each of our policies, and subject to various policy limits, exclusions and conditions, based upon 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: the 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 determine the cause of the leak, the value of lost natural gas and costs incurred to mitigate the actual natural gas released, the costs

associated with litigation and claims by nearby residents and businesses, the cost to clean additional homes as directed by the DPH, 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 control of well costs 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 insurance coverage for these costs under the applicable policies, and to the extent we are not successful, it could result in a material charge against the earnings of SoCalGas and Sempra Energy.

Our estimate as of September 30, 2016 of $763 million of certain costs in connection with the Aliso Canyon storage facility leak may rise significantly as more information becomes available, 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. In addition, any costs not included in the $763 million estimate could be material, and to the extent not covered by insurance (including any costs in excess of applicable policy limits), 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 the DOGGR, DPH, South Coast Air Quality Management District (SCAQMD), California Air Resources Board (CARB), Los Angeles Regional Water Quality Control Board (RWQCB), California Division of Occupational Safety and Health (DOSH), CPUC, Pipeline and Hazardous Materials Safety Administration (PHMSA), U.S. Environmental Protection Agency (EPA), Los Angeles County District Attorney’s Office and California Attorney General’s Office, are investigating this incident. Other federal agencies (e.g., the U.S. Departments of Energy (DOE) and Interior (DOI)) also are investigating the incident as part of the joint interagency task force discussed below. On January 25, 2016, the DOGGR and CPUC selected Blade Energy Partners (Blade) to conduct an independent analysis under their supervision and to be funded by SoCalGas to investigate the technical root cause of the Aliso Canyon gas leak. We expect the root cause analysis to be completed in the first half of 2017, but the timing is under the control of Blade, the DOGGR and the CPUC.

As of November 1, 2016, 212 lawsuits, including over 12,000 plaintiffs, have been filed in the Los Angeles County Superior Court against SoCalGas, some of which have also named Sempra Energy. These various lawsuits assert causes of action for negligence, negligence per se, strict liability, property damage, fraud, public and private nuisance (continuing and permanent), trespass, inverse condemnation, fraudulent concealment, unfair business practices and loss of consortium, among other things, and additional litigation may be filed against us in the future related to this incident. A complaint alleging violations of Proposition 65 was also filed. Many of these complaints seek class action status, compensatory and punitive damages, civil penalties, injunctive relief, costs of future medical monitoring and attorneys’ fees. All of these cases, other than a matter brought by the Los Angeles County District Attorney, the federal securities class action and the four shareholder derivative actions discussed below, are coordinated before a single court in the Los Angeles County Superior Court for pretrial management.

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 directors in the United States District Court for the Southern District of California, and four shareholder derivative actions alleging breach of fiduciary duties have been filed against certain officers and directors of Sempra Energy and/or SoCalGas, one in the San Diego County Superior Court, one in the United States District Court for the Southern District of California, and two in the Los Angeles County Superior Court.

Pursuant to the parties’ agreement, the Los Angeles County Superior Court ordered that the individual and business entity plaintiffs (other than the Proposition 65 case, the federal securities class action and the shareholder derivative actions), would proceed by filing consolidated master complaints. Accordingly, on July 25, 2016, the individuals and business entities asserting tort claims filed a Consolidated 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 and loss of consortium against SoCalGas, with certain causes also naming Sempra Energy. The consolidated complaint seeks compensatory and punitive damages for personal injuries, property damage and diminution in property value, a temporary injunction, costs of future medical monitoring, and attorneys’ fees.

On August 8, 2016, also pursuant to the coordination proceeding, a Consolidated Property Class Action Complaint on behalf of a putative class of persons and businesses who own or lease real property within a five-mile radius of the well was filed against SoCalGas and Sempra Energy. The complaint asserts claims for strict liability for ultra-hazardous activities, negligence, negligence per se, trespass, permanent and continuing public and private nuisance, violation of the California Unfair Competition Law and inverse condemnation, and seeks compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees.

Also on August 8, 2016, a Consolidated Class Action Business Complaint was filed against SoCalGas and Sempra Energy on behalf of a putative class of all persons and entities conducting business within five miles of the Aliso Canyon facility. The complaint asserts claims for strict liability for ultra-hazardous activities, negligence, negligent interference with prospective economic advantage and

violation of the California Unfair Competition Law, and seeks compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees.

Three complaints have also been filed by public entities, as follows. These lawsuits are included in the coordinated proceedings in the Los Angeles County Superior Court. On August 8, 2016, the California Attorney General, acting in her 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.

The SCAQMD filed a complaint against SoCalGas seeking civil penalties for alleged violations of several nuisance-related statutory provisions arising from the leak and delays in stopping the leak. That suit seeks up to $250,000 in civil penalties for each day the violations occurred. On July 13, 2016, the SCAQMD amended its complaint to seek a declaration that SoCalGas is required to pay the costs of a longitudinal study of the health of persons exposed to the gas leak.

On July 25, 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 Los Angeles County 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 or formerly operated by SoCalGas in Los Angeles County require safety upgrades, including the installation of sub-surface safety shut-off valves 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.

Separately, on February 2, 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. On February 16, 2016, SoCalGas pled not guilty to the complaint. On September 13, 2016, SoCalGas entered a plea of 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 $232,500, and up to $4 million in operational commitments, reimbursement and assessments in exchange for the District Attorney’s Office moving to dismiss the remaining counts at sentencing and settling the complaint. The sentencing hearing is currently scheduled for November 29, 2016, at which we expect the court to rule on the motion to dismiss and determine whether to enter judgment on the notice count pursuant to the plea agreement. On October 18, 2016, certain plaintiffs in the separate civil cases filed a “Victims’ Request for Withdrawal of Plea Agreement” seeking to have the court order the withdrawal of the no contest plea or permit a restitution hearing on the nuisance count (SoCalGas pled not guilty to the nuisance count, which under the plea agreement is to be dismissed at sentencing). SoCalGas is implementing the operational commitments pursuant to the terms of the settlement agreement, and we expect that upon completion of those commitments and all other obligations of SoCalGas under the settlement agreement, the District Attorney will move to dismiss the remaining counts at the sentencing hearing.

The costs of defending against these civil and criminal lawsuits and cooperating with these investigations, and any damages, restitution, and civil and criminal fines, costs and other penalties, 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, could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Governmental Orders, Additional Regulation and Reliability. On January 6, 2016, the Governor of the State of California issued the Governor’s Order proclaiming a state of emergency to exist in Los Angeles County due to the natural gas leak at the Aliso Canyon facility. The Governor’s Order directs the following:

•

Protecting Public Health and Safety: State agencies will: continue the prohibition against SoCalGas injecting any gas into the Aliso Canyon storage facility until a comprehensive review, utilizing independent experts, of the safety of the storage wells and the air quality of the surrounding community is completed; expand real-time monitoring of emissions in the surrounding community; 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; and take all actions necessary to ensure the continued reliability of natural gas and electricity supplies in the coming months during the moratorium on gas injections into the Aliso Canyon storage facility.


•	Ensuring Accountability: The CPUC will ensure that SoCalGas covers costs related to the natural gas leak and its response, while protecting ratepayers; and CARB will develop a program to fully mitigate the leak’s emissions of methane by March 31, 2016, with such program to be funded by SoCalGas.

•

Strengthening Oversight: The DOGGR will promulgate emergency regulations for gas storage facility operators throughout the state, requiring: at least daily inspection of gas storage well heads using gas leak detection technology such as infrared imaging; ongoing verification of the mechanical integrity of all gas storage wells; ongoing measurement of annular gas pressure or annular gas flow within wells; regular testing of all safety valves used in wells; minimum and maximum pressure limits for each gas storage facility in the state; and a comprehensive risk management plan for each facility that evaluates and prepares for risks, including corrosion potential of pipes and equipment. Additionally, the DOGGR, CPUC, CARB and California Energy Commission (CEC) will submit to the Governor’s Office a report that assesses the long-term viability of natural gas storage facilities in California.

SoCalGas made a commitment in December 2015 to mitigate the actual natural gas released from the leak and has been working on a plan to accomplish the mitigation. On March 31, 2016, pursuant to the Governor’s Order, the CARB issued its Aliso Canyon Methane Leak Climate Impacts Mitigation Program, which sets forth its recommended approach to achieve full mitigation of the emissions from the Aliso Canyon natural gas leak. The CARB program states that full mitigation requires that the program generate reductions in short-lived climate pollutants and other greenhouse gases at least equivalent to that amount and that the appropriate global warming potential to be used in deriving the amount of reductions required is 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 provides that all of the mitigation is to occur in California over the next five to ten years without the use of allowances or offsets.

On October 21, 2016, CARB issued its final report, Determination of Total Methane Emissions from the Aliso Canyon Natural Gas Leak Incident. The report documents the CARB staff’s determination of the total methane emissions and the amount needed for full mitigation of the climate impacts. CARB concluded that the incident resulted in total emissions from 90,350 to 108,950 metric tons of methane. CARB also asserted that to fully mitigate the greenhouse gas impacts of the leak, the upper bound of the estimate should be used, and therefore SoCalGas should mitigate 109,000 metric tons of methane. We have not agreed with CARB’s estimate of methane released and continue to work with CARB on the mitigation plan.

On January 23, 2016, the Hearing Board of the SCAQMD ordered SoCalGas to, among other things: stop all injections of natural gas except as directed by the CPUC, withdraw the maximum amount of natural gas feasible in a contained and safe manner, subject to orders of the CPUC, and permanently seal the well once the leak has ceased; continuously monitor the well site with infrared cameras until 30 days after the leak has ceased; provide the public with daily air monitoring data collected by SoCalGas; provide the SCAQMD with certain natural gas injection, withdrawal and emissions data from the Aliso Canyon facility; prepare and submit to the SCAQMD for its approval an enhanced leak detection and reporting well inspection program for the Aliso Canyon facility; provide the SCAQMD with funding to develop a continuous air monitoring plan for the Aliso Canyon facility and the nearby schools and community; prepare and submit to the SCAQMD for its approval an air quality notification plan to provide notice to SCAQMD, other public agencies and the nearby community in the event of a future reportable release; and provide the SCAQMD with funding to conduct an independent health study on the potential impacts of exposure on the constituents of the natural gas released from the facility, as well as any odor suppressants used to mitigate odors from the leaking well. SoCalGas has fulfilled its obligations under all of the conditions set forth in the Abatement Order to the satisfaction of the SCAQMD and its Hearing Board, with the exception of the condition that SoCalGas agree to fund the reasonable costs of a study of the health impacts of the leak. While SoCalGas tendered an offer to fund the reasonable costs of a health study and a proposed scope of work for the study, SCAQMD responded that this offer was not acceptable. To date, SCAQMD has not tendered a proposed scope of work or costs to SoCalGas for payment. As described above, SCAQMD amended its civil complaint against SoCalGas to seek a declaration that SoCalGas is required to pay the costs of a longitudinal study of the health of persons exposed to the gas leak. At a September 17, 2016 status hearing, the Hearing Board scheduled a status report hearing on January 18, 2017 regarding the progress of compliance with the health study condition and whether to extend the order, which is set to expire on January 31, 2017.

On April 1, 2016, the Secretary of the DOE and PHMSA jointly announced the formation of an Interagency Task Force on Natural Gas Storage Safety in response to the leak at Aliso Canyon to assess and make recommendations on best practices, response plans and safe operation of gas storage facilities. On June 22, 2016, President Obama signed the “Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016” or the “PIPES Act of 2016.” Among other things, the PIPES Act: (1) requires PHMSA to issue, within two years of passage, “minimum safety standards for underground natural gas storage facilities;” (2) imposes a “user fee” on underground storage facilities as needed to implement the safety standards; (3) grants PHMSA authority to issue emergency orders and impose emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for hearing, if the Secretary of Energy determines that an unsafe condition or practice, or a combination of unsafe conditions and practices, constitutes or is causing an imminent hazard; and (4) directs the Secretary of Energy to establish an Aliso Canyon Task Force comprised of representatives from the Department of Transportation (DOT), Department of Health and Human Services, EPA, DOI, Department of Commerce, FERC and representatives of state and local governments, as deemed appropriate by the Secretary and the Administrator. The Act expressly allows states to adopt more stringent standards for intrastate underground natural gas storage facilities if such standards are compatible with the minimum standards prescribed under the PIPES Act.

On October 18, 2016, the Interagency Task Force issued its report and recommendations. Overall, the report finds that “while incidents at U.S. underground natural gas storage facilities are rare, the potential consequences of those incidents can be significant and require additional actions to ensure safe and reliable operation over the long term.” In particular, the report recommends that PHMSA adopt as a preliminary set of safety regulations the requirements set out in American Petroleum Institute (API) Recommended Practice 1171, Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs. The report further provides 44 specific recommendations to industry, federal, state, and local regulators and governments intended to reduce the likelihood of future leaks and minimize the impacts of any that occur. We are reviewing the report and recommendations, which may result in additional regulations.

PHMSA, DOGGR, SCAQMD, EPA and CARB have each commenced separate rulemaking proceedings to adopt further regulations covering natural gas storage facilities and injection wells. Regulations issued by DOGGR following the Governor’s Order, as well as California Senate Bill 380, enacted on May 10, 2016, California Senate Bill 887, enacted on September 26, 2016, and California Senate Bill 888, enacted on September 23, 2016, are discussed below. Additional hearings in the State Legislature, as well as with various other federal and state regulatory agencies, have been or are expected to be scheduled, additional legislation has been proposed in the State Legislature, and additional laws, orders, rules and regulations may be adopted. The Los Angeles County Board of Supervisors has formed a task force to review and potentially implement new, more stringent land use (zoning) requirements and associated regulations and enforcement protocols for oil and gas activities, including natural gas storage field operations. Such new requirements could materially affect new or modified uses of the Aliso Canyon and other natural gas storage fields located in the County, including review under the California Environmental Quality Act and mitigation of environmental impacts associated with new and modified uses of the fields.

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 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.

On June 10, 2016, DOSH issued four citations to SoCalGas alleging violations of various regulations, including that SoCalGas failed to ensure that testing and inspection of well casing and tubing at the Aliso Canyon storage facility complied with testing and inspection requirements, with total penalties of $60,800. On June 27, 2016, SoCalGas filed an appeal of all four citations on the grounds that no violations of the cited regulations occurred, the citations are all preempted by federal law, the citations were not issued in a timely manner, and two of the citations are duplicative.

Adoption of SB 380. The California legislature enacted and the Governor signed Senate Bill (SB) 380, which among other things: (1) continues the prohibition against SoCalGas injecting any natural gas into the Aliso Canyon natural gas storage facility until a comprehensive review of the safety of the gas storage wells at the facility is completed in accordance with regulations adopted by the DOGGR, the State Oil and Gas Supervisor has made a safety determination and other required findings, at least one public hearing has been held in the affected community, and the Executive Director of the CPUC has issued a concurring letter regarding the Supervisor’s determination of safety; (2) requires that all gas storage wells returning to service shall only inject or produce gas through the interior metal tubing and not through the annulus between the tubing and the well casing, which will result in diminished field production capability; (3) requires the CPUC, in consultation with various governmental agencies and other entities, to determine the range of working gas necessary in Aliso Canyon to ensure safety and reliability for the region and just and reasonable rates in California and publish a report that includes such range and the number of wells and associated injection and production capacity required; (4) requires seeking public comments on the report either through written comments or a workshop; and (5) requires the CPUC, no later than July 1, 2017, to open a proceeding to determine the feasibility of minimizing or eliminating use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region, and to consult with various governmental agencies and other entities in making its determination.

As required by SB 380, on June 28, 2016, the CPUC published the report, Aliso Canyon Working Gas Inventory, Production Capacity, Injection Capacity, and Well Availability for Summer 2016 Reliability (SB 380 Report), which incorporates, and is based on the findings of, the Aliso Canyon Risk Assessment Technical Report which was prepared by the staff of the CAISO, CEC, Los Angeles Department of Water and Power (LADWP), SoCalGas and the CPUC. In that report, among other things, the CPUC determined that SoCalGas would need a withdrawal capacity of 1.119 billion cubic feet (Bcf) per day to meet the reliability needs of customers. In addition, the CPUC directed SoCalGas to keep 17 specified wells that have completed the Phase I testing required by DOGGR available for reliability-related withdrawals. On September 28, 2016, the CPUC authorized SoCalGas to isolate and remove from service the 17 wells that had been kept available for reliability-related withdrawals, so long as SoCalGas maintains a minimum daily withdrawal capacity of 8.6 million cubic feet (MMcf) per hour or 207 MMcf per day at Aliso Canyon.

Adoption of SB 887. The California legislature enacted and the Governor signed SB 887, which establishes a framework for revising State regulations over natural gas storage wells in California. Among other things, the statute directs: (1) CARB, in consultation with any local air district and DOGGR, to develop a natural gas storage facility monitoring program that includes continuous monitoring of the ambient concentration of natural gas to identify natural gas leaks and the presence of natural gas emissions in the atmosphere; (2)

DOGGR, in consultation with CARB, to determine by regulation what constitutes a reportable leak from a gas storage well and the timeframe for reporting those leaks; (3) DOGGR to perform random onsite inspections of some gas storage wells annually and post the results on its website; (4) the operator of a gas storage well to develop and maintain a comprehensive gas storage well training and mentoring program for those employees whose job duties involve the safety of operations and maintenance of gas storage wells and associated equipment; and (5) the operator of a natural gas storage well to submit to DOGGR for review and approval a comprehensive set of data and information, including, among other things, data to demonstrate stored gas will be confined to an approved zone, a risk management plan and a natural gas leak prevention and response plan.

Adoption of SB 888. The California legislature enacted and the Governor signed SB 888, which requires that a penalty assessed against a gas corporation by the CPUC pursuant to the Public Utilities Act with regard to a natural gas storage facility leak must at least equal the amount necessary to fully offset the impact on the climate from the greenhouse gases emitted by the leak, as determined by CARB. The statute further requires the CPUC to consider the extent to which the gas corporation has mitigated or is in the process of mitigating the impact on the climate from greenhouse gas emissions resulting from the leak.

Natural Gas Storage Operations. SoCalGas estimates that approximately 57 Bcf of natural gas was delivered to customers from an initial starting point of approximately 77 Bcf of gas in storage on October 23, 2015 at the Aliso Canyon facility. SoCalGas completed its measurement of the natural gas lost from the leak and 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. In January 2016, the CPUC directed SoCalGas to retain a minimum of 15 Bcf of working natural gas to help ensure reliability of the system, with withdrawals permitted only to meet reliability needs under a limited set of circumstances. Effective February 5, 2016, the DOGGR issued Emergency Regulations that amended the California Code of Regulations to require all underground natural gas storage facility operators, including SoCalGas, to take further steps to help ensure the safety of their gas storage operations. On July 8, 2016, DOGGR issued a Discussion Draft of new permanent regulations for all storage fields in California.

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. Aliso Canyon, with a storage capacity of 86 Bcf, is the largest SoCalGas storage facility and an important element of SoCalGas’ delivery system. Aliso Canyon represents 63 percent of SoCalGas’ owned natural gas storage inventory capacity. SoCalGas has not injected natural gas into Aliso Canyon since October 25, 2015, in accordance with the Governor’s Order, but in conflict with the CPUC’s reliability-based direction, which requires injections to reach higher inventory levels prior to the winter season. On March 4, 2016, the DOGGR issued Order 1109, Order to Take Specific Actions Regarding Aliso Canyon Gas Storage Facility (Safety Review Testing Regime). On April 7, 2016, SoCalGas announced its safety framework to comply with the DOGGR Order 1109, which consists of phased testing for each of the active injection wells in the Aliso Canyon storage facility. SoCalGas will continue this moratorium on further injections until all required approvals have been obtained.

On November 1, 2016, SoCalGas submitted a request to DOGGR to resume injection operations at the Aliso Canyon storage facility. Under SB 380, before authorizing the commencement of injections at the facility, DOGGR must hold a public meeting in the affected community to provide the public an opportunity to comment on the safety review findings, and the CPUC must concur with DOGGR’s safety determination in writing.

On April 5, 2016, four energy agencies—the CPUC, CEC, CAISO, and LADWP—issued an Aliso Canyon Action Plan to Preserve Gas and Electric Reliability for the Los Angeles Basin. In their Action Plan, the agencies recognized that Aliso Canyon is critical to meeting peak demand in both winter and summer. To help mitigate concerns about natural gas service reliability to customers, including related impacts on natural gas-fueled power generation, SoCalGas, SDG&E and 24 customer organizations filed a settlement agreement with the CPUC on April 29, 2016 regarding procedures to help deal with service reliability issues. The procedures, which address supply shortages and surpluses using temporarily modified Operational Flow Order (OFO) tariff provisions, were approved by the CPUC on June 9, 2016, and will be in place through no later than November 30, 2016. There can be no assurance that these measures will prevent gas curtailments or power outages.

If the Aliso Canyon facility were to be taken out of service for any meaningful period of time, it could result in an impairment of the facility, significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At September 30, 2016, the Aliso Canyon facility has a net book value of $491 million, including $217 million of construction work in progress for the project to construct a new compression 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 SoCalGas’ and Sempra Energy’s results of operations, cash flows and financial condition may be materially adversely affected.

Other

SoCalGas, along with Monsanto Co., Solutia, Inc., Pharmacia Corp. and Pfizer, Inc., are defendants in seven Los Angeles County Superior Court lawsuits filed beginning in April 2011 seeking recovery of unspecified amounts of damages, including punitive

damages, as a result of plaintiffs’ exposure to PCBs (polychlorinated biphenyls). The lawsuits allege plaintiffs were exposed to PCBs not only through the food chain and other various sources but from PCB-contaminated natural gas pipelines owned and operated by SoCalGas. This contamination allegedly caused plaintiffs to develop cancer and other serious illnesses. Plaintiffs assert various bases for recovery, including negligence and products liability. SoCalGas has settled six of the seven lawsuits for an amount that is not significant.

Sempra Mexico

Permit Challenges and Property Disputes

Sempra Mexico has been engaged in a long-running land dispute relating to property adjacent to its Energía Costa Azul LNG terminal near Ensenada, Mexico. Ownership of the adjacent property is not required by any of the environmental or other regulatory permits issued for the operation of the terminal. A claimant to the adjacent property has nonetheless asserted that his health and safety are endangered by the operation of the facility, and filed an action in the Federal Court challenging the permits. In February 2011, based on a complaint by the claimant, the municipality of Ensenada opened an administrative proceeding and sought to temporarily close the terminal based on claims of irregularities in municipal permits issued six years earlier. This attempt was promptly countermanded by Mexican federal and Baja California state authorities. No terminal permits or operations were affected as a result of these proceedings or events and the terminal has continued to operate normally. In the second quarter of 2014, the municipality of Ensenada dismissed the administrative proceeding. In the second quarter of 2015, the Administrative Court of Baja California confirmed the municipality of Ensenada’s ruling and dismissed the proceeding. In September 2016, the Federal Court dismissed the lawsuit in which the permits were challenged.

The claimant also filed complaints in the federal Agrarian Court challenging the refusal of the Secretaría de la Reforma Agraria (now the Secretaría de Desarrollo Agrario, Territorial y Urbano, or SEDATU) in 2006 to issue a title to him for the disputed property. In November 2013, the 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. Sempra Mexico expects additional proceedings regarding the claims, although such proceedings are not related to the permit challenges referenced above.

The property claimant also filed a lawsuit in July 2010 against Sempra Energy in Federal District Court in San Diego seeking compensatory and punitive damages as well as the earnings from the Energía Costa Azul LNG terminal based on his allegations that he was wrongfully evicted from the adjacent property and that he has been harmed by other allegedly improper actions. In September 2015, the Court granted Sempra Energy’s motion for summary judgment and closed the case. In October 2015, the claimant filed a notice of appeal of the summary judgment and an earlier order dismissing certain of his causes of action.

Additionally, several administrative challenges are pending in Mexico before the Mexican environmental protection agency (SEMARNAT) and the Federal Tax and Administrative Courts seeking revocation of the environmental impact authorization (EIA) issued to Energía Costa Azul in 2003. These cases generally allege that the conditions and mitigation measures in the EIA are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines. The Mexican Supreme Court decided to exercise jurisdiction over one such case, and in March 2014, issued a resolution denying the relief sought by the plaintiff on the grounds its action was not timely presented. A similar administrative challenge seeking to revoke the port concession for our marine operations at our Energía Costa Azul LNG terminal was filed with and rejected by the Mexican Communications and Transportation Ministry. In April 2015, the Federal court confirmed the Mexican Communications and Transportation Ministry’s ruling denying the request to revoke the port concession and decided in favor of Energía Costa Azul.

Two real property cases have been filed against Energía Costa Azul in which the plaintiffs seek to annul the recorded property titles for parcels on which the Energía Costa Azul LNG terminal is situated and to obtain possession of different parcels that allegedly sit in the same place; one of these cases was dismissed in September 2013 at the direction of the state appellate court. A third complaint was served in April 2013 seeking to invalidate the contract by which Energía Costa Azul purchased another of the terminal parcels, on the grounds the purchase price was unfair. Sempra Mexico expects further proceedings on the remaining two matters.

In 2015, the Yaqui tribe, with the exception of the Bácum community, granted its consent and a right of way easement agreement for the construction of the Guaymas-El Oro segment that crosses its territory. Representatives of the Bácum community filed an amparo claim in Mexican Federal Court demanding the right to withhold consent for the project, the stoppage of work in the Yaqui territory and damages. The judge granted a suspension order that prohibited the construction through the Bácum community territory only. As a result, IEnova has been delayed in the construction of approximately 14 kilometers of the Guaymas-El Oro segment of IEnova’s Sonora Pipelines that pass through territory of the Yaqui tribe. While IEnova continues to seek the consent of the Bácum community, it intends to continue construction along such route. IEnova may reroute the pipeline, however, if the circumstances so warrant. Efforts to obtain consent or reroute the pipeline could cause added expense and delays in completion of the pipeline. There can be no assurance that the CFE will agree to extend the deadline for commercial operations or provide payment of transportation services in the event of such delay.

Sempra Natural Gas

Beginning in April 2012, a series of lawsuits were filed against Mobile Gas in Mobile County Circuit Court alleging that in the first half of 2008 Mobile Gas spilled tert-butyl mercaptan, an odorant added to natural gas for safety reasons, in Eight Mile, Alabama. Under the terms of the agreement to sell the outstanding equity of EnergySouth, the parent company of Mobile Gas, as discussed in Note 3, this litigation and any associated liabilities and insurance receivable were retained by Mobile Gas at the close of the transaction in September 2016.

Other Litigation

Sempra Energy holds a noncontrolling interest in RBS Sempra Commodities LLP (RBS Sempra Commodities), a limited liability partnership in the process of being liquidated. The Royal Bank of Scotland plc (RBS), our partner in the joint venture, was notified by the United Kingdom’s Revenue and Customs Department (HMRC) that it was investigating value-added tax (VAT) refund claims made by various businesses in connection with the purchase and sale of carbon credit allowances. HMRC advised RBS that it had determined that it had grounds to deny such claims by RBS related to transactions by RBS Sempra Energy Europe (RBS SEE), a former indirect subsidiary of RBS Sempra Commodities that was sold to JP Morgan. HMRC asserted that RBS was not entitled to reduce its VAT liability by VAT paid during 2009 because RBS knew or should have known that certain vendors in the trading chain did not remit their own VAT to HMRC. In September 2012, HMRC issued a protective assessment of £86 million for the VAT paid in connection with these transactions. In October 2014, RBS filed a Notice of Appeal of the September 2012 assessment with the First-tier Tribunal. As a condition of the appeal, RBS was required to pay the assessed amount. The payment also stops the accrual of interest that could arise should it ultimately be determined that RBS has a liability for some of the tax. RBS has asserted that HMRC’s assessment was time-barred. The First-Tier Tribunal held a preliminary hearing on the time-bar issue in September 2016, but has not yet issued its decision. In June 2015, liquidators for three 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 against RBS and RBS Sempra Commodities alleging that RBS Sempra Commodities’ and RBS SEE’s participation in transactions involving the sale and purchase of carbon credits resulted in the companies’ incurring VAT liability they were unable to pay. In October 2015, the liquidators’ counsel filed an amended claim adding seven additional trading companies to the claim and asserting damages of £146 million for all 10 companies. Additionally, the claimants dropped RBS Sempra Commodities LLP as a defendant, adding the successor to RBS SEE and JP Morgan, Mercuria Energy Europe Trading Limited (Mercuria), in its stead. JP Morgan has notified us that Mercuria has sought indemnity for the claim, and JP Morgan has in turn sought indemnity from us. Our remaining balance in RBS Sempra Commodities is accounted for under the equity method. The investment balance of $67 million at September 30, 2016 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. We discuss RBS Sempra Commodities further in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

In August 2007, the U.S. Court of Appeals for the Ninth Circuit issued a decision reversing and remanding certain FERC orders declining to provide refunds regarding short-term bilateral sales up to one month in the Pacific Northwest for the January 2000 to June 2001 time period. In December 2010, the FERC approved a comprehensive settlement previously reached by Sempra Energy and RBS Sempra Commodities with the State of California. The settlement resolved all issues with regard to sales between the California Department of Water Resources and Sempra Commodities in the Pacific Northwest, but potential claims may exist regarding sales in the Pacific Northwest between Sempra Commodities and other parties. The FERC is in the process of addressing these potential claims on remand. Pursuant to the agreements related to the formation of RBS Sempra Commodities, we have indemnified RBS for any liability from the final resolution of these matters. Pursuant to our agreement with the Noble Group Ltd., one of the buyers of RBS Sempra Commodities’ businesses, we have also indemnified Noble Americas Gas & Power Corp. and its affiliates for all losses incurred by such parties resulting from these proceedings as related to Sempra Commodities.

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 AND OTHER COMMITMENTS

We discuss below significant changes in the first nine months of 2016 to contractual commitments discussed in Notes 1 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Natural Gas Contracts

Sempra Natural Gas’ natural gas purchase and transportation commitments have decreased by $224 million since December 31, 2015, primarily due to payments on existing contracts and changes in forward natural gas prices in the first nine months of 2016. Net future payments are expected to decrease by $168 million in 2016, increase by $2 million in 2017 and decrease by $17 million in 2018, $20 million in 2019, $8 million in 2020 and $13 million thereafter compared to December 31, 2015.

In the second quarter of 2016, Sempra Natural Gas permanently released pipeline capacity that it held with Rockies Express and others. The effect of the permanent capacity releases resulted in a pretax charge of $206 million ($123 million after-tax), which is included in Other Cost of Sales on the Sempra Energy Condensed Consolidated Statement of Operations in the nine months ended September 30, 2016. The charge represents an acceleration of costs that would otherwise have been recognized over the duration of the contracts. In connection with the capacity releases, Sempra Natural Gas has recorded $44 million in Other Current Liabilities and $106 million in Deferred Credits and Other on the Sempra Energy Condensed Consolidated Balance Sheet at September 30, 2016, representing the amounts by which Sempra Natural Gas’ obligation to make future capacity payments is expected to exceed proceeds generated from the permanent capacity releases.

LNG Purchase Agreement

Sempra Natural Gas has a purchase agreement for the supply of LNG to the Energía Costa Azul terminal. The agreement is priced using a predetermined formula based on natural gas market indices. Although this contract specifies a number of cargoes to be delivered, under its terms, the customer may divert certain cargoes, which would reduce amounts paid under the contracts by Sempra Natural Gas.

Sempra Natural Gas’ commitment under the LNG purchase agreement, reflecting changes in forward prices since December 31, 2015 and actual transactions for the first nine months of 2016, is expected to decrease by $306 million in 2016, increase by $41 million in 2017, and decrease by $18 million in 2018, $59 million in 2019, $98 million in 2020 and $542 million thereafter (through contract termination in 2029) compared to December 31, 2015. These amounts are based on forward prices of the index applicable to the contract from 2016 to 2028 and an estimated one percent escalation in 2029. The LNG commitment amounts above are based on the requirement for Sempra Natural Gas to accept the maximum possible delivery of cargoes under the agreement. Actual LNG purchases in the current and prior years have been significantly lower than the maximum amounts possible due to the customer electing to divert cargoes as allowed by the agreement.

Purchased-Power Contracts

SDG&E’s commitments under purchased-power contracts have increased by $526 million since December 31, 2015, primarily due to the settlement agreement for the Rim Rock Wind Farm, discussed above. Net future payments are expected to increase by $19 million in 2016, $56 million in 2017, $57 million each year in 2018 through 2020 and $280 million thereafter compared to December 31, 2015.

In July 2016, the Ministry of Energy and Mines in Peru amended the basis upon which tolling fees are billed for transmission connection from the generator to the distributor. Prior to the change in law, tolling fees were based on contracted capacity. As a result of the change in law, tolling fees are now based on coincident peak demand. At December 31, 2015, Sempra South American Utilities’ commitments under purchased-power contracts included $1.4 billion of tolling fees that were fixed and determinable. These tolling fees are now variable based on customers’ coincident peak demand.

Construction and Development Projects

In connection with the acquisition of GdC in September 2016, as we discuss in Note 3, contractual commitments for ongoing maintenance services at Sempra Mexico increased by $180 million. The future payments for these contractual commitments are expected to be $4 million in 2016, $15 million each year in 2017 and 2018, $16 million each year in 2019 and 2020, and $114 million thereafter.

Asset Retirement Obligations

Contractual commitments for asset retirement obligations at SDG&E, SoCalGas and Sempra Energy Consolidated increased by $26 million, $316 million and $342 million, respectively, since December 31, 2015, primarily for natural gas assets, as a result of updated cost studies completed for the 2016 GRC filing. We discuss the 2016 GRC in Note 10.

Guarantees

We discuss guarantees related to Sempra Energy in Note 4 above and in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. This insurance provides $375 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides for up to $13.2 billion of secondary financial protection (SFP). If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $375 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. SDG&E’s contribution would be up to $50.93 million. This amount is subject to an annual maximum

of $7.6 million, unless a default occurs by any other SONGS owner. If the SFP is insufficient to cover the liability loss, SDG&E could be subject to an additional assessment.

The SONGS owners, including SDG&E, also have $2.75 billion of nuclear property, decontamination, and debris removal insurance, subject to a $2.5 million deductible for “each and every loss.” This insurance coverage is provided through Nuclear Electric Insurance Limited (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 $9.7 million of retrospective premiums based on overall member claims. See Note 9 under “Settlement with NEIL” for discussion of an agreement between the SONGS co-owners and NEIL to settle all claims under the NEIL policies associated with the SONGS outage.

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). The industry aggregate loss limit for property claims arising from non-certified acts of terrorism is $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.

U.S. DEPARTMENT OF ENERGY NUCLEAR FUEL DISPOSAL

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. On April 18, 2016, Edison executed a spent fuel settlement agreement with the DOE for $162 million covering damages incurred from January 1, 2006 through December 31, 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 operation and maintenance 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. SDG&E’s respective share of the claim is $11 million. It is unclear whether the claim will be resolved through settlement or arbitration, when resolution is expected, and whether Edison will receive an award for the full claim amount.

In October 2015, the California Coastal Commission approved Edison’s application for the proposed expansion of an Independent Spent Fuel Storage Installation (ISFSI) at SONGS. The ISFSI expansion began construction in 2016, will be fully loaded with spent fuel by 2019, and will 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.

We provide additional information about SONGS in Note 9 above and in Notes 13 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

CONCENTRATION OF CREDIT RISK

We maintain credit policies and systems 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.

As they become operational, projects owned or partially owned by Sempra Natural Gas, Sempra Renewables, Sempra South American Utilities and Sempra Mexico 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.

NOTE 12. SEGMENT INFORMATION

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


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


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


3.	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 transmission pipelines and propane and ethane systems, a liquid petroleum gas pipeline and associated storage terminal, a natural gas distribution utility, electric generation facilities (including wind and solar), a terminal for the import of LNG, and marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico. In February 2016, management approved a plan to market and sell the TdM natural gas-fired power plant located in Mexicali, Baja California, as we discuss in Note 3.


5.	Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy projects in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Michigan, Minnesota, Nebraska, Nevada and Pennsylvania to serve wholesale electricity markets in the United States.

Sempra Natural Gas develops, owns and operates, or holds interests in, natural gas pipelines and storage facilities and a terminal for the import and export of LNG and sale of natural gas, all within the United States. In September 2016, Sempra Natural Gas sold EnergySouth, the parent company of Mobile Gas and Willmut Gas, and in May 2016, sold its 25-percent interest in Rockies Express, as we discuss in Note 3. Sempra Natural Gas also owned and operated the Mesquite Power plant, a natural gas-fired electric generation asset, the remaining 625-MW block of which was sold in April 2015.

Sempra South American Utilities and Sempra Mexico comprise our Sempra International operating unit. Sempra Renewables and Sempra Natural Gas comprise our Sempra U.S. Gas & Power operating unit.

We evaluate each segment’s performance based on its contribution to Sempra Energy’s reported earnings. 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 parent organizations.



SEGMENT INFORMATION
(Dollars in millions)
	Three months ended September 30,										Nine months ended September 30,
	2016					2015					2016					2015
REVENUES
SDG&E	$	1,209		48	%	$	1,230		50	%	$	3,192		44	%	$	3,168		42	%
SoCalGas	686			27		620			25		2,336			32		2,448			33
Sempra South American Utilities	385			15		373			15		1,170			16		1,151			15
Sempra Mexico	196			8		193			8		481			7		508			7
Sempra Renewables	12			1		12			—		25			—		30			—
Sempra Natural Gas	164			6		160			6		384			5		512			7
Adjustments and eliminations	(1		)	—		—			—		(1		)	—		(1		)	—
Intersegment revenues(1)	(116		)	(5	)	(107		)	(4	)	(274		)	(4	)	(286		)	(4	)
Total	$	2,535		100	%	$	2,481		100	%	$	7,313		100	%	$	7,530		100	%
INTEREST EXPENSE
SDG&E	$	49				$	51				$	145				$	155
SoCalGas	25					23					71					61
Sempra South American Utilities	9					9					29					22
Sempra Mexico	5					7					13					18
Sempra Renewables	—					1					—					3
Sempra Natural Gas	11					13					33					57
All other	68					65					214					193
Intercompany eliminations	(31		)			(26		)			(84		)			(93		)
Total	$	136				$	143				$	421				$	416
INTEREST INCOME
SoCalGas	$	—				$	—				$	—				$	3
Sempra South American Utilities	5					5					15					14
Sempra Mexico	2					1					5					5
Sempra Renewables	1					2					2					3
Sempra Natural Gas	19					16					52					60
All other	1					—					1					—
Intercompany eliminations	(21		)			(18		)			(56		)			(62		)
Total	$	7				$	6				$	19				$	23
DEPRECIATION AND AMORTIZATION
SDG&E	$	161		49	%	$	152		48	%	$	478		49	%	$	446		48	%
SoCalGas	121			37		116			37		355			37		342			37
Sempra South American Utilities	14			4		12			4		41			4		37			4
Sempra Mexico	15			5		18			6		47			5		52			6
Sempra Renewables	1			—		2			—		4			—		5			—
Sempra Natural Gas	12			4		12			4		37			4		36			4
All other	4			1		3			1		8			1		7			1
Total	$	328		100	%	$	315		100	%	$	970		100	%	$	925		100	%
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	91				$	75				$	204				$	217
SoCalGas	21					(20		)			75					91
Sempra South American Utilities	17					16					46					50
Sempra Mexico	142					(6		)			170					7
Sempra Renewables	(7		)			(9		)			(29		)			(37		)
Sempra Natural Gas	51					—					(77		)			29
All other	(33		)			(41		)			(105		)			(81		)
Total	$	282				$	15				$	284				$	276



SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016					2015
EQUITY EARNINGS (LOSSES)
Earnings (losses) recorded before tax:
Sempra Renewables	$	12		$	8		$	30				$	20
Sempra Natural Gas	—			25			(26		)			59
Total	$	12		$	33		$	4				$	79
Earnings (losses) recorded net of tax:
Sempra South American Utilities	$	1		$	(3	)	$	3				$	(4	)
Sempra Mexico	18			30			66					68
Total	$	19		$	27		$	69				$	64
EARNINGS (LOSSES)
SDG&E	$	183		$	170		$	419				$	443
SoCalGas(2)	—			(8		)	198					276
Sempra South American Utilities	46			43			127					129
Sempra Mexico	332			63			407					160
Sempra Renewables	17			15			43					47
Sempra Natural Gas	77			1			(104		)			43
All other	(33		)	(36		)	(99		)			(118		)
Total	$	622		$	248		$	991				$	980
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E							$	959		31	%	$	835		38	%
SoCalGas							949			31		946			42
Sempra South American Utilities							133			4		105			5
Sempra Mexico							232			8		185			8
Sempra Renewables							700			23		47			2
Sempra Natural Gas							100			3		61			3
All other							14			—		48			2
Total							$	3,087		100	%	$	2,227		100	%

							September 30, 2016					December 31, 2015
ASSETS
SDG&E							$	17,446		38	%	$	16,515		40	%
SoCalGas							13,148			29		12,104			29
Sempra South American Utilities							3,488			8		3,235			8
Sempra Mexico							6,359			14		3,783			9
Sempra Renewables							2,112			5		1,441			4
Sempra Natural Gas							5,377			12		5,566			13
All other							640			1		734			2
Intersegment receivables							(3,044		)	(7	)	(2,228		)	(5	)
Total							$	45,526		100	%	$	41,150		100	%
EQUITY METHOD AND OTHER INVESTMENTS
Sempra South American Utilities							$	(1	)			$	(4	)
Sempra Mexico							108					519
Sempra Renewables							819					855
Sempra Natural Gas							838					1,460
All other							76					75
Total							$	1,840				$	2,905

(1)

Revenues for reportable segments include intersegment revenues of $2 million, $21 million, $26 million and $67 million for the three months ended September 30, 2016; $5 million, $56 million, $80 million and $133 million for the nine months ended September 30, 2016; $2 million, $19 million, $24 million and $62 million for the three months ended September 30, 2015; and $7 million, $55 million, $73 million and $151 million for the nine months ended September 30, 2015 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.


(2)	After preferred dividends.

NOTE 13. SUBSEQUENT EVENT

On October 13, 2016, IEnova priced a private follow-on offering of its common stock (which trades under the symbol IENOVA on the Mexican Stock Exchange) in the U.S. and outside of Mexico (the International Offering) and a concurrent public common stock offering in Mexico (the Mexican Offering) at 80.00 Mexican pesos per share. The initial purchasers in the International Offering and the underwriters in the Mexican Offering were granted a 30-day option to purchase additional common shares at the global offering price, less the underwriting discount, to cover overallotments. These options were exercised on October 17, 2016. Sempra Energy also participated in the Mexican Offering by purchasing 83,125,000 shares of common stock for approximately $351 million. After the offerings and the exercise of the overallotment options, the aggregate shares of common stock sold in the offerings totaled 380,000,000. Upon completion of the offerings on October 19, 2016, Sempra Energy beneficially owns approximately 66.4 percent of IEnova.

The net proceeds of the offerings, including the additional option shares, were approximately $1.57 billion in U.S. dollars or 29.86 billion Mexican pesos. IEnova used the net proceeds of the offerings to repay the $1.150 billion bridge loan from Sempra Global that was used to finance the GdC acquisition and expects to use part of such proceeds to pay for a portion of the purchase price to acquire Ventika in the fourth quarter of 2016. We discuss these acquisitions in Note 3. Any remaining proceeds will be used to fund capital expenditures and for general corporate purposes.

All U.S. dollar equivalents presented here were based on an exchange rate of 18.96 Mexican pesos to 1.00 U.S. dollar as of October 13, 2016, the pricing date for the offerings. Net proceeds are after reduction for underwriting discounts and commissions and offering expenses.

The International Offering was exempt from registration under the U.S. Securities Act of 1933, as amended (the Securities Act), and shares in the International Offering were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside of the United States, in accordance with Regulation S under the Securities Act. The shares were not registered under the Securities Act or any state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act and applicable securities laws.

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, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors” contained in our 2015 Annual Report on Form 10-K (Annual Report).

OVERVIEW

Sempra Energy is a Fortune 500 energy-services holding company whose operating units invest in, develop and operate energy infrastructure, and provide gas and electricity services to their customers in North and South America. Our operating units are our California Utilities, which are San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), Sempra International and Sempra U.S. Gas & Power. SDG&E and SoCalGas are separate, reportable segments. Sempra International includes two reportable segments – Sempra South American Utilities and Sempra Mexico. Sempra U.S. Gas & Power also includes two reportable segments – Sempra Renewables and Sempra Natural Gas.

This report includes information for the following separate registrants:


▪	Sempra Energy and its consolidated entities


▪	SDG&E


▪	SoCalGas

References to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by its context. All references to “Sempra International” and “Sempra U.S. Gas & Power,” and to their respective principal 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 variable interest entities (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.

Below are summary descriptions of our operating units and their reportable segments.

SEMPRA ENERGY OPERATING UNITS AND REPORTABLE SEGMENTS



CALIFORNIA UTILITIES
	MARKET	SERVICE TERRITORY
SAN DIEGO GAS & ELECTRIC COMPANY (SDG&E) A regulated public utility; infrastructure supports electric generation, transmission and distribution, and natural gas distribution	▪ Provides electricity to a population of 3.6 million (1.4 million meters) ▪ Provides natural gas to a population of 3.3 million (0.9 million meters)	Serves the county of San Diego, California and an adjacent portion of southern Orange County covering 4,100 square miles
SOUTHERN CALIFORNIA GAS COMPANY (SOCALGAS) A regulated public utility; infrastructure supports natural gas distribution, transmission and storage	▪ Residential, commercial, industrial, utility electric generation and wholesale customers ▪ Covers a population of 21.6 million (5.9 million meters)	Southern California and portions of central California (excluding San Diego County, the city of Long Beach and the desert area of San Bernardino County) covering 20,000 square miles

We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include the utilities in our Sempra International or Sempra U.S. Gas & Power operating units described below.



SEMPRA INTERNATIONAL
	MARKET	GEOGRAPHIC REGION
SEMPRA SOUTH AMERICAN UTILITIES Develops, owns and operates, or holds interests in electric transmission, distribution and generation infrastructure	▪ Provides electricity to a population of approximately 2 million (approximately 672,000 meters) in Chile and approximately 4.9 million consumers (approximately 1,053,000 meters) in Peru	▪ Chile ▪ Peru
SEMPRA MEXICO Develops, owns and operates, or holds interests in: ▪ natural gas transmission pipelines and propane and ethane systems ▪ a liquid petroleum gas pipeline and associated storage terminal ▪ a natural gas distribution utility ▪ electric generation facilities, including wind and solar ▪ a terminal for the import of liquefied natural gas (LNG) ▪ marketing operations for the purchase of LNG and the purchase and sale of natural gas	▪ Natural gas ▪ Wholesale electricity ▪ Liquefied natural gas ▪ Liquid petroleum gas	▪ Mexico



SEMPRA U.S. GAS & POWER
	MARKET	GEOGRAPHIC REGION
SEMPRA RENEWABLES Develops, owns, operates, or holds interests in renewable energy generation projects	▪ Wholesale electricity	▪ U.S.A.
SEMPRA NATURAL GAS Develops, owns and operates, or holds interests in natural gas midstream and LNG operations: ▪ natural gas pipelines and storage facilities ▪ a terminal in the U.S. for the import and export of LNG and sale of natural gas ▪ marketing operations	▪ Natural gas ▪ Liquefied natural gas	▪ U.S.A.

RESULTS OF OPERATIONS

We discuss the following in Results of Operations:


▪	Overall results of our operations and factors affecting those results


▪	Our segment results


▪	Significant changes in revenues, costs and earnings between periods

SEMPRA ENERGY CONSOLIDATED OVERALL RESULTS

Our earnings increased by $374 million to $622 million in the three months ended September 30, 2016, while diluted earnings per share increased by $1.47 per share to $2.46 per share. For the nine months ended September 30, 2016, our earnings increased by $11 million to $991 million, while diluted earnings per share increased by $0.02 per share to $3.93 per share.

The net increases in our earnings and diluted earnings per share for the three-month period ended September 30, 2016 were primarily due to the following increases (decreases), by segment. Where applicable, certain items below include a reference to a note in the Notes to Condensed Consolidated Financial Statements herein where we provide additional information.

SDG&E


▪	$10 million higher earnings from California Public Utilities Commission (CPUC) base operations

SoCalGas


▪	$9 million higher earnings from CPUC base operations


▪	$7 million higher earnings associated with the Pipeline Safety Enhancement Plan (PSEP) and advanced metering assets (Note 10 and below in “Factors Influencing Future Performance – California Utilities”)


▪	$(10) million lower favorable impact in 2016 related to the resolution of prior years’ income tax items

Sempra Mexico


▪	$350 million noncash gain associated with the remeasurement of our equity interest in Gasoductos de Chihuahua S. de R.L. de C.V. (GdC) (Note 3)


▪	$25 million impact from reduction of a deferred Mexican income tax liability on our basis difference in the Termoeléctrica de Mexicali (TdM) natural gas-fired power plant as a result of the impairment of the assets held for sale (Note 3)


▪	$(90) million impairment of TdM assets held for sale (Notes 3 and 8)


▪	$(4) million unfavorable impact in 2016 compared to $(16) million favorable impact in 2015 due primarily to transactional effects from foreign currency and inflation, including amounts in equity earnings from our joint ventures

Sempra Natural Gas


▪	$78 million gain on the sale of EnergySouth Inc. (EnergySouth), the parent company of Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas Company (Willmut Gas) (Note 3)

Parent and Other


▪	$7 million investment gain in 2016 compared to an $11 million investment loss in 2015 on dedicated assets in support of our executive retirement and deferred compensation plans, net of the change in deferred compensation liability associated with the investments


▪	$(11) million higher U.S. income tax expense in 2016, primarily due to a reduction in 2015 in forecasted planned repatriation of full year 2015 earnings from certain non-U.S. subsidiaries

The net increases in our earnings and diluted earnings per share for the nine-month period ended September 30, 2016 were primarily due to the following increases (decreases), by segment:

SDG&E


▪	$9 million higher earnings from CPUC base operations


▪	$8 million increase in allowance for funds used during construction (AFUDC) related to equity


▪	$7 million related to excess tax benefits associated with the adoption of a new accounting standard related to share-based compensation (Note 2)


▪	$(31) million of charges associated with prior years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the CPUC final decision in the 2016 General Rate Case (2016 GRC FD) (Note 10)


▪	$(13) million decrease due to the plant closure adjustment recorded in the first quarter of 2015 based on the CPUC approval of a compliance filing related to SDG&E’s authorized recovery of its investment in the San Onofre Nuclear Generating Station (SONGS) (Note 9)


▪	$(11) million lower favorable impact related to the resolution of prior years’ income tax items

SoCalGas


▪	$17 million higher earnings associated with the PSEP and advanced metering assets


▪	$15 million higher earnings from CPUC base operations


▪	$(49) million of charges associated with prior years’ income tax benefits generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD (Note 10)


▪	$(13) million lower favorable impact in 2016 related to the resolution of prior years’ income tax items


▪	$(13) million impairment of assets related to the Southern Gas System Reliability Project (also referred to as the North-South Pipeline) (Note 10)


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


▪	$(11) million charge associated with tracking the 2016 income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD (Notes 5 and 10)


▪	$(8) million after-tax gas cost incentive mechanism (GCIM) award approved by the CPUC in the first quarter of 2015 for the 12-month period ending March 31, 2014

Sempra South American Utilities


▪	$9 million higher earnings from operations mainly due to the start of operations of the Santa Teresa hydroelectric power plant in September 2015


▪	$(6) million lower earnings from foreign currency translation and inflation effects

Sempra Mexico


▪	$350 million noncash gain associated with the remeasurement of our equity interest in GdC


▪	$(90) million impairment of assets held for sale at TdM

Sempra Natural Gas


▪	$78 million gain on the sale of EnergySouth


▪	$(123) million loss on permanent release of pipeline capacity (Note 11)


▪	$(36) million gain in 2015 on the sale of the remaining 625-megawatt (MW) block of the Mesquite Power plant


▪	$(31) million lower results primarily from midstream activities, including $(12) million mark-to-market losses on commodity contracts in 2016 compared to $(9) million mark-to-market gains in 2015, mainly driven by changes in natural gas prices


▪	$(27) million impairment charge in the first quarter of 2016 related to Sempra Natural Gas’ investment in Rockies Express Pipeline, LLC (Rockies Express) (Notes 3 and 8)

Parent and Other


▪	$17 million investment gain in 2016 compared to a $5 million investment loss in 2015 on dedicated assets in support of our executive retirement and deferred compensation plans, net of the increase in deferred compensation liability associated with the investments


▪	$8 million higher income tax benefits, including $17 million related to excess tax benefits associated with the adoption of a new accounting standard related to share-based compensation (Note 2)


▪	$(13) million higher net interest expense in 2016, primarily due to debt issuances in the fourth quarter of 2015

ADJUSTED EARNINGS AND ADJUSTED EARNINGS PER SHARE

We prepare the Condensed Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP). However, for Sempra Energy Consolidated, management may use earnings and earnings per share adjusted to exclude certain items (adjusted earnings and adjusted earnings per share) 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 earnings per share when communicating our financial results and earnings outlook to analysts and investors. Adjusted earnings and adjusted earnings per share 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 more meaningful comparison of the performance of Sempra Energy’s 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 adjusted earnings and adjusted earnings per share to Sempra Energy Earnings and Diluted Earnings Per Common Share, which we consider to be the most directly comparable financial measures calculated in accordance with U.S. GAAP, for the three months and nine months ended September 30, 2016 and the nine months ended September 30, 2015. There were no excluded items to adjust U.S. GAAP earnings in the three months ended September 30, 2015.



SEMPRA ENERGY ADJUSTED EARNINGS AND ADJUSTED EARNINGS PER SHARE
(Dollars in millions, except per share amounts)
	Pretax amount			Income tax expense (benefit)(1)			Non-controlling interests			Earnings			Diluted EPS
	Three months ended September 30, 2016
Sempra Energy GAAP Earnings										$	622		$	2.46
Excluded items:
Remeasurement gain in connection with GdC	$	(617	)	$	185		$	82		(350		)	(1.39		)
Gain on sale of EnergySouth	(130		)	52			—			(78		)	(0.31		)
Impairment of TdM assets held for sale	131			(20		)	(21		)	90			0.36
Reduction of deferred income tax liability associated with TdM	—			(31		)	6			(25		)	(0.10		)
Sempra Energy Adjusted Earnings										$	259		$	1.02
Weighted-average number of shares outstanding, diluted (thousands)													252,405
	Nine months ended September 30, 2016
Sempra Energy GAAP Earnings										$	991		$	3.93
Excluded items:
Remeasurement gain in connection with GdC	$	(617	)	$	185		$	82		(350		)	(1.39		)
Gain on sale of EnergySouth	(130		)	52			—			(78		)	(0.31		)
Permanent release of pipeline capacity	206			(83		)	—			123			0.49
SDG&E tax repairs adjustments related to 2016 GRC FD	52			(21		)	—			31			0.12
SoCalGas tax repairs adjustments related to 2016 GRC FD	83			(34		)	—			49			0.20
Impairment of investment in Rockies Express	44			(17		)	—			27			0.11
Impairment of TdM assets held for sale	131			(20		)	(21		)	90			0.36
Deferred income tax expense associated with TdM	—			1			—			1			—
Sempra Energy Adjusted Earnings										$	884		$	3.51
Weighted-average number of shares outstanding, diluted (thousands)													251,976

	Nine months ended September 30, 2015
Sempra Energy GAAP Earnings										$	980		$	3.91
Excluded items:
Gain on sale of Mesquite Power block 2	$	(61	)	$	25		$	—		(36		)	(0.14		)
SONGS plant closure adjustment	(21		)	8			—			(13		)	(0.05		)
Sempra Energy Adjusted Earnings										$	931		$	3.72
Weighted-average number of shares outstanding, diluted (thousands)													250,665


(1)	Income taxes were calculated based on applicable statutory tax rates, except for adjustments that are solely income tax. Income taxes on the impairment of TdM were calculated based on the applicable statutory tax rate, including translation from historic to current exchange rates.

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). Variance amounts are the after-tax earnings impact (based on applicable statutory tax rates), and are after noncontrolling interests for Sempra South American Utilities and Sempra Mexico, unless otherwise noted.



SEMPRA ENERGY EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)
	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
California Utilities:
SDG&E	$	183		$	170		$	419		$	443
SoCalGas(1)	—			(8		)	198			276
Sempra International:
Sempra South American Utilities	46			43			127			129
Sempra Mexico	332			63			407			160
Sempra U.S. Gas & Power:
Sempra Renewables	17			15			43			47
Sempra Natural Gas	77			1			(104		)	43
Parent and other(2)	(33		)	(36		)	(99		)	(118		)
Earnings	$	622		$	248		$	991		$	980


(1)	After preferred dividends.


(2)	Includes after-tax interest expense ($41 million and $38 million for the three months ended September 30, 2016 and 2015, respectively,

and $128 million and $115 million for the nine months ended September 30, 2016 and 2015, respectively), intercompany eliminations

recorded in consolidation and certain corporate costs.

CALIFORNIA UTILITIES

SDG&E

Our SDG&E segment recorded earnings of:


▪	$183 million in the three months ended September 30, 2016


▪	$170 million in the three months ended September 30, 2015


▪	$419 million for the first nine months of 2016


▪	$443 million for the first nine months of 2015

The increase in earnings of $13 million (8%) in the three months ended September 30, 2016 was primarily due to:


▪	$10 million higher CPUC base operating margin authorized for 2016, net of higher non-refundable operating costs; and


▪	$2 million increase in AFUDC related to equity.

The decrease in earnings of $24 million (5%) in the first nine months of 2016 was primarily due to:


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


▪	$13 million decrease due to the plant closure adjustment recorded in the first quarter of 2015 based on the CPUC approval of a compliance filing related to SDG&E’s authorized recovery of its investment in SONGS; and


▪	$9 million favorable impact in 2016 related to the resolution of prior years’ income tax items compared to $20 million favorable impact in 2015; offset by


▪	$9 million higher CPUC base operating margin authorized for 2016, including lower generation major maintenance, net of higher non-refundable operating costs;


▪	$8 million increase in AFUDC related to equity;


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


▪	$7 million lower net interest expense.

SoCalGas

Our SoCalGas segment recorded (losses) earnings of:


▪	a negligible amount in the three months ended September 30, 2016 (both before and after preferred dividends)


▪	$(8) million in the three months ended September 30, 2015 (both before and after preferred dividends)


▪	$198 million for the first nine months of 2016 ($199 million before preferred dividends)


▪	$276 million for the first nine months of 2015 ($277 million before preferred dividends)

The decrease in losses of $8 million in the three months ended September 30, 2016 was primarily due to:


▪	$9 million higher CPUC base operating margin authorized for 2016, and lower non-refundable operating costs; and


▪	$7 million higher earnings associated with the PSEP and advanced metering assets; offset by


▪	$10 million lower favorable impact in 2016 related to the resolution of prior years’ income tax items.

The decrease in earnings of $78 million (28%) in the first nine months of 2016 was primarily due to:


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


▪	$13 million lower favorable impact in 2016 related to the resolution of prior years’ income tax items;


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


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


▪	$11 million charge associated with tracking the 2016 income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD, as we discuss in Notes 5 and 10;


▪	$8 million after-tax GCIM award approved by the CPUC in February 2015 for the 12-month period ending March 31, 2014. We include incentive awards in earnings when we receive any required CPUC approval of the award, which may cause timing differences in earnings. In December 2015, SoCalGas received approval of a $4 million after-tax GCIM award for the 12-month period ending March 31, 2015;


▪	$6 million from the favorable resolution of a legal settlement in 2015, including $2 million of related interest income; and


▪	$6 million higher net interest expense primarily due to debt issuances in the second quarter of 2015; offset by


▪	$17 million higher earnings associated with the PSEP and advanced metering assets; and


▪	$15 million higher CPUC base operating margin authorized for 2016, and lower non-refundable operating costs.

SEMPRA INTERNATIONAL

Because our operations in South America 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. The year-to-year variances discussed below are as adjusted for the difference in foreign currency translation rates between periods. We discuss these and other foreign currency effects below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.”

Earnings variances below for both Sempra South American Utilities and Sempra Mexico exclude amounts attributable to noncontrolling interests.

Sempra South American Utilities

Our Sempra South American Utilities segment recorded earnings of:


▪	$46 million in the three months ended September 30, 2016


▪	$43 million in the three months ended September 30, 2015


▪	$127 million for the first nine months of 2016


▪	$129 million for the first nine months of 2015

The increase in earnings of $3 million (7%) in the three months ended September 30, 2016 was primarily due to the start of operations of the Santa Teresa hydroelectric power plant in September 2015.

The decrease in earnings of $2 million (2%) in the first nine months of 2016 was primarily due to:


▪	$6 million lower earnings from foreign currency translation and inflation effects; and


▪	$4 million primarily due to lower capitalized interest due to completion of construction of the Santa Teresa hydroelectric power plant in 2015; offset by


▪	$9 million higher earnings from operations mainly due to the start of operations of the Santa Teresa hydroelectric power plant in September 2015.

Sempra Mexico

Our Sempra Mexico segment recorded earnings of:


▪	$332 million in the three months ended September 30, 2016


▪	$63 million in the three months ended September 30, 2015


▪	$407 million for the first nine months of 2016


▪	$160 million for the first nine months of 2015

The increase in earnings of $269 million in the three months ended September 30, 2016 was primarily due to:


▪	$350 million noncash gain associated with the remeasurement of our equity interest in GdC;


▪	$25 million reduction in deferred Mexican income tax liability on our basis difference in TdM as a result of the impairment of the assets held for sale; and


▪	$2 million increase in earnings from operations from our distribution company mainly associated with new distribution rates; offset by


▪	$90 million impairment of TdM assets held for sale; and


▪	$4 million unfavorable impact in 2016 compared to $16 million favorable impact in 2015 due primarily to transactional effects from foreign currency and inflation, including amounts in equity earnings from our joint ventures. We discuss these effects below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.”

The increase in earnings of $247 million in the first nine months of 2016 was primarily due to:


▪	$350 million noncash gain associated with the remeasurement of our equity interest in GdC; and


▪	$5 million increase in earnings from operations from our distribution company mainly associated with new distribution rates; offset by


▪	$90 million impairment of TdM assets held for sale; and


▪	$14 million favorable impact in 2016 compared to $26 million favorable impact in 2015 due primarily to transactional effects from foreign currency and inflation, including amounts in equity earnings from our joint ventures.

SEMPRA U.S. GAS & POWER

Sempra Renewables

Our Sempra Renewables segment recorded earnings of:


▪	$17 million in the three months ended September 30, 2016


▪	$15 million in the three months ended September 30, 2015


▪	$43 million for the first nine months of 2016


▪	$47 million for the first nine months of 2015

The increase in earnings of $2 million (13%) in the three months ended September 30, 2016 was primarily due to increased production at wind projects.

The decrease in earnings of $4 million (9%) in the first nine months of 2016 was primarily due to:


▪	$8 million lower solar investment tax credits from projects placed in service in 2015; offset by


▪	$5 million higher earnings from increased production at wind projects.

Sempra Natural Gas

Our Sempra Natural Gas segment recorded earnings (losses) of:


▪	$77 million in the three months ended September 30, 2016


▪	$1 million in the three months ended September 30, 2015


▪	$(104) million for the first nine months of 2016


▪	$43 million for the first nine months of 2015

The increase in earnings of $76 million in the three months ended September 30, 2016 was primarily due to:


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


▪	$8 million higher results primarily from midstream activities, including $4 million higher results from LNG marketing operations; offset by


▪	$14 million lower equity earnings resulting from the sale of its investment in Rockies Express.

The change in the first nine months of 2016 was primarily due to:


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


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


▪	$31 million lower results primarily from midstream activities, including $12 million mark-to-market losses on commodity contracts in 2016 compared to $9 million mark-to-market gains in 2015, mainly driven by changes in natural gas prices;


▪	$27 million impairment charge in the first quarter of 2016 related to the investment in Rockies Express; and


▪	$20 million lower equity earnings resulting from the sale of the investment in Rockies Express; offset by


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

Parent and Other

Losses for Parent and Other were


▪	$33 million in the three months ended September 30, 2016


▪	$36 million in the three months ended September 30, 2015


▪	$99 million for the first nine months of 2016


▪	$118 million for the first nine months of 2015

The decrease in losses of $3 million (8%) in the three months ended September 30, 2016 was primarily due to:


▪	$7 million investment gain in 2016 compared to an $11 million investment loss in 2015 on dedicated assets in support of our executive retirement and deferred compensation plans, net of the change in deferred compensation liability associated with the investments; offset by


▪	$11 million higher U.S. income tax expense in 2016, primarily due to a reduction in 2015 in forecasted planned repatriation of full year 2015 earnings from certain non-U.S. subsidiaries; and


▪	$5 million higher retained operating costs in 2016, primarily due to insurance recovery of certain litigation costs in 2015.

The decrease in losses of $19 million (16%) in the first nine months of 2016 was primarily due to:


▪	$17 million investment gain in 2016 compared to a $5 million investment loss in 2015 on dedicated assets in support of our executive retirement and deferred compensation plans, net of the increase in deferred compensation liability associated with the investments; and


▪	$8 million higher income tax benefits in 2016, including:


◦	$17 million related to excess tax benefits associated with the adoption of a new accounting standard related to share-based compensation, and


◦	$5 million lower U.S. tax expense in 2016 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries, offset by


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


◦	$5 million in net state income tax refunds in 2015 related to our former commodities-marketing businesses; offset by


▪	$13 million higher net interest expense in 2016, primarily due to debt issuances in the fourth quarter of 2015.

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

Natural gas revenues at:


▪	SDG&E


▪	SoCalGas


▪	Sempra Mexico’s Ecogas México, S. de R.L. de C.V. (Ecogas)


▪	Sempra Natural Gas’ Mobile Gas and Willmut Gas (prior to September 12, 2016)

Electric revenues at:


▪	SDG&E


▪	Sempra South American Utilities’ Chilquinta Energía S.A. (Chilquinta Energía) and Luz del Sur S.A.A. (Luz del Sur)

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

The California Utilities

The current regulatory framework for SoCalGas and SDG&E 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 Notes 1 and 14 of the Notes to Consolidated Financial Statements in the Annual Report.

The regulatory framework also 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.

The table below summarizes revenues and cost of sales for our utilities, net of intercompany activity:



UTILITIES REVENUES AND COST OF SALES
(Dollars in millions)
	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
Electric revenues:
SDG&E	$	1,111		$	1,140		$	2,851		$	2,819
Sempra South American Utilities	359			351			1,102			1,077
Eliminations and adjustments	(1		)	(2		)	(4		)	(6		)
Total	1,469			1,489			3,949			3,890
Natural gas revenues:
SoCalGas	686			620			2,336			2,448
SDG&E	98			90			341			349
Sempra Mexico	22			18			64			62
Sempra Natural Gas	12			16			68			76
Eliminations and adjustments	(23		)	(20		)	(58		)	(57		)
Total	795			724			2,751			2,878
Total utilities revenues	$	2,264		$	2,213		$	6,700		$	6,768
Cost of electric fuel and purchased power:
SDG&E	$	364		$	427		$	926		$	906
Sempra South American Utilities	240			239			754			739
Total	$	604		$	666		$	1,680		$	1,645
Cost of natural gas:
SoCalGas	$	171		$	163		$	571		$	626
SDG&E	25			27			89			112
Sempra Mexico	13			12			36			38
Sempra Natural Gas	3			4			18			24
Eliminations and adjustments	(4		)	(5		)	(12		)	(14		)
Total	$	208		$	201		$	702		$	786

Sempra Energy Consolidated

Electric Revenues

During the three months ended September 30, 2016, our electric revenues decreased by $20 million (1%), remaining at $1.5 billion primarily due to:


▪	$29 million decrease at SDG&E, which included


◦	$63 million lower cost of electric fuel and purchased power, which we discuss below, offset by


◦	$17 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses,


◦	$15 million higher authorized revenue in the 2016 GRC FD, and


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


▪	$8 million increase at Sempra South American Utilities, which included


◦	$22 million due to higher rates at Luz del Sur and Chilquinta Energía primarily due to $13 million of increased costs passed through to customers, offset by


◦	$9 million lower volumes at Luz del Sur, net of the effects of higher revenues from the Santa Teresa hydroelectric power plant, which began commercial operations in September 2015, and


◦	$6 million due to foreign currency exchange rate effects.

Our utilities’ cost of electric fuel and purchased power decreased by $62 million (9%) to $604 million in the three months ended September 30, 2016 primarily due to a $63 million decrease at SDG&E, which we discuss below.

During the nine months ended September 30, 2016, our electric revenues increased by $59 million (2%), remaining at $3.9 billion primarily due to:


▪	$32 million increase at SDG&E, which included


◦	$42 million higher authorized revenue in the 2016 GRC FD,


◦	$42 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses,


◦	$20 million higher cost of electric fuel and purchased power, which we discuss below, and


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


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


▪	$25 million increase at Sempra South American Utilities, which included


◦	$107 million due to higher rates at Luz del Sur and Chilquinta Energía primarily due to $77 million of increased costs passed through to customers, offset by


◦	$70 million due to foreign currency exchange rate effects, and


◦	$13 million lower volumes at Luz del Sur, net of the effects of higher revenues from the Santa Teresa hydroelectric power plant, which began commercial operations in September 2015.

Our utilities’ cost of electric fuel and purchased power increased by $35 million (2%) to $1.7 billion in the nine months ended September 30, 2016 due to:


▪	$20 million increase at SDG&E, which we discuss below; and


▪	$15 million increase at Sempra South American Utilities driven primarily by higher prices at both Luz del Sur and Chilquinta Energía, offset by foreign currency exchange rate effects, and lower volumes at Luz del Sur.

We discuss the changes in electric revenues and the cost of electric fuel and purchased power for SDG&E in more detail below.

Natural Gas Revenues

During the three months ended September 30, 2016, Sempra Energy’s natural gas revenues increased by $71 million (10%) to $795 million, and the cost of natural gas increased by $7 million (3%) to $208 million. The increase in natural gas revenues was primarily due to:


▪	$66 million increase at SoCalGas, which included


◦	the increase in cost of natural gas sold, as we discuss below,


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


◦	$18 million higher revenues primarily associated with the PSEP and advanced metering assets,


◦	$17 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses, and


◦	$10 million higher authorized revenue in the 2016 GRC FD, offset by


◦	$4 million charge associated with tracking the 2016 income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD.

In the first nine months of 2016, Sempra Energy’s natural gas revenues decreased by $127 million (4%) to $2.8 billion, and the cost of natural gas decreased by $84 million (11%) to $702 million. The decrease in natural gas revenues was primarily due to:


▪	$112 million decrease at SoCalGas, which included


◦	the decrease in cost of natural gas sold, as we discuss below,


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


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


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


◦	$14 million GCIM award approved by the CPUC in February 2015. We include incentive awards in earnings when we receive any required CPUC approval of the award, which may cause timing differences in earnings. In December 2015, SoCalGas received approval of a $7 million pretax GCIM award for the 12-month period ending March 31, 2015, and


◦	$12 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses, offset by


◦	$44 million higher revenues primarily associated with the PSEP and advanced metering assets,


◦	$35 million higher authorized revenue in the 2016 GRC FD, and


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


▪	$23 million decrease in cost of natural gas sold at SDG&E, as we discuss below.

We discuss the changes in natural gas revenues and the cost of natural gas individually for SDG&E and SoCalGas below.

SDG&E: Electric Revenues and Cost of Electric Fuel and Purchased Power

The table below shows electric revenues for SDG&E for the nine months ended September 30, 2016 and 2015. Because the cost of electricity is substantially recovered in rates, changes in the cost are reflected in the changes in revenues. In addition to the change in cost, electric 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 1 of the Notes to Consolidated Financial Statements in the Annual Report.

100



SDG&E
ELECTRIC DISTRIBUTION AND TRANSMISSION
(Volumes in millions of kilowatt-hours, dollars in millions)
	Nine months ended September 30, 2016			Nine months ended September 30, 2015
Customer class	Volumes	Revenue		Volumes	Revenue
Residential	5,031	$	1,058	5,257	$	1,096
Commercial	4,953	961		5,112	1,116
Industrial	1,623	261		1,519	268
Direct access	2,573	163		2,683	170
Street and highway lighting	55	10		62	11
	14,235	2,453		14,633	2,661
CAISO shared transmission revenue - net(1)		198			214
Other revenues		131			166
Balancing accounts		69			(222		)
Total(2)		$	2,851		$	2,819


(1)	California Independent System Operator (CAISO).


(2)	Includes sales to affiliates of $4 million in 2016 and $6 million in 2015.

For the three months ended September 30, 2016, SDG&E’s electric revenues decreased by $29 million (3%), remaining at $1.1 billion. The change was primarily due to:


▪	$63 million decrease in cost of electric fuel and purchased power, including:


◦	a decrease in consumption due to increased energy efficiency initiatives, including rooftop solar installations,


◦	higher energy and capacity costs in 2015 due to plant outages at SDG&E-owned generation facilities, and


◦	a decrease in the cost of purchased power due to declining natural gas prices; offset by


▪	$17 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses;


▪	$15 million higher authorized revenue in the 2016 GRC FD; and


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

In the first nine months of 2016, SDG&E’s electric revenues increased by $32 million (1%) to $2.9 billion primarily due to:


▪	$42 million higher authorized revenue in the 2016 GRC FD;


▪	$42 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses;


▪	$20 million increase in cost of electric fuel and purchased power, including:


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


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


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


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


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

SDG&E and SoCalGas: Natural Gas Revenues and Cost of Natural Gas

The tables below show natural gas revenues for SDG&E and SoCalGas for the nine months ended September 30, 2016 and 2015. Because the cost of natural gas is recovered in rates, changes in the cost are reflected in the changes in revenues. In addition to the change in market prices, natural gas revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-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 1 of the Notes to Consolidated Financial Statements in the Annual Report.

101



SDG&E
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
	Natural gas sales			Transportation			Total
Customer class	Volumes	Revenue		Volumes	Revenue		Volumes	Revenue
Nine months ended September 30, 2016:
Residential	20	$	240	—	$	1	20	$	241
Commercial and industrial	10	76		7	15		17	91
Electric generation plants	—	—		16	3		16	3
	30	$	316	23	$	19	53	335
Other revenues								50
Balancing accounts								(44		)
Total(1)								$	341
Nine months ended September 30, 2015:
Residential	18	$	222	—	$	2	18	$	224
Commercial and industrial	10	74		6	10		16	84
Electric generation plants	—	—		20	—		20	—
	28	$	296	26	$	12	54	308
Other revenues								31
Balancing accounts								10
Total(1)								$	349


(1)	Includes sales to affiliates of $1 million in 2016 and $2 million in 2015.

During the three months ended September 30, 2016, SDG&E’s natural gas revenues increased by $8 million (9%) to $98 million and the cost of natural gas sold decreased by $2 million (7%) to $25 million. The increase in revenues was primarily due to higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expense.

SDG&E’s average cost of natural gas for the three months ended September 30, 2016 was $3.73 per thousand cubic feet (Mcf) compared to $4.07 per Mcf for the corresponding period in 2015, an 8-percent decrease of $0.34 per Mcf, resulting in lower revenues and cost of $2 million.

During the nine months ended September 30, 2016, SDG&E’s natural gas revenues decreased by $8 million (2%) to $341 million, and the cost of natural gas sold decreased by $23 million (21%) to $89 million. The decrease in revenues was primarily due to lower cost of natural gas sold, offset by higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expense.

SDG&E’s average cost of natural gas for the nine months ended September 30, 2016 was $2.93 per Mcf compared to $3.94 per Mcf for the corresponding period in 2015, a 26-percent decrease of $1.01 per Mcf, resulting in lower revenues and cost of $31 million. The decrease in the cost of natural gas sold was offset by higher sales volumes from a cooler winter in 2016 compared to the same period in 2015, which resulted in higher revenues and cost of $8 million.

102



SOCALGAS
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
	Natural gas sales			Transportation			Total
Customer class	Volumes	Revenue		Volumes	Revenue		Volumes	Revenue
Nine months ended September 30, 2016:
Residential	143	$	1,496	1	$	9	144	$	1,505
Commercial and industrial	69	478		221	205		290	683
Electric generation plants	—	—		132	26		132	26
Wholesale	—	—		100	17		100	17
	212	$	1,974	454	$	257	666	2,231
Other revenues								134
Balancing accounts								(29		)
Total(1)								$	2,336
Nine months ended September 30, 2015:
Residential	132	$	1,373	2	$	12	134	$	1,385
Commercial and industrial	67	451		213	198		280	649
Electric generation plants	—	—		147	31		147	31
Wholesale	—	—		112	20		112	20
	199	$	1,824	474	$	261	673	2,085
Other revenues								131
Balancing accounts								232
Total(1)								$	2,448


(1)	Includes sales to affiliates of $56 million in 2016 and $55 million in 2015.

During the three months ended September 30, 2016, SoCalGas’ natural gas revenues increased by $66 million (11%) to $686 million, and the cost of natural gas sold increased by $8 million (5%) to $171 million. The revenue increase included


▪	the increase in the cost of natural gas sold, as we discuss below;


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


▪	$18 million higher revenues primarily associated with the PSEP and advanced metering assets;


▪	$17 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; and


▪	$10 million higher authorized revenue in the 2016 GRC FD; offset by


▪	$4 million charge associated with tracking the 2016 income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD.

SoCalGas’ average cost of natural gas for the three months ended September 30, 2016 was $3.48 per Mcf compared to $3.40 per Mcf for the corresponding period in 2015, a 2-percent increase of $0.08 per Mcf, resulting in higher revenues and cost of $3 million. The increase in the cost of natural gas sold was also due to higher sales volumes.

During the nine months ended September 30, 2016, SoCalGas’ natural gas revenues decreased by $112 million (5%) to $2.3 billion, and the cost of natural gas sold decreased by $55 million (9%) to $571 million. The revenue decrease included


▪	the decrease in the cost of natural gas sold, as we discuss below;


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


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


▪	$19 million charge associated with tracking the 2016 income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD;


▪	$14 million GCIM award approved by the CPUC in February 2015; and


▪	$12 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; offset by


▪	$44 million higher revenues primarily associated with the PSEP and advanced metering assets;


▪	$35 million higher authorized revenue in the 2016 GRC FD; and

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

For the first nine months of 2016, SoCalGas’ average cost of natural gas was $2.72 per Mcf compared to $3.16 per Mcf for the corresponding period in 2015, a 14-percent decrease of $0.44 per Mcf, resulting in lower revenues and cost of $93 million. The decrease in the cost of natural gas sold was offset by higher sales volumes from a cooler winter in 2016 compared to the same period in 2015, which resulted in higher revenues and cost of $38 million.

Other Utilities: Revenues and Cost of Sales

Revenues generated by Chilquinta Energía and Luz del Sur 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. The bases for the tariffs do not meet the requirements necessary for regulatory accounting treatment under applicable U.S. GAAP. We discuss revenue recognition further for Chilquinta Energía and Luz del Sur in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Operations of Mobile Gas, Willmut Gas and Ecogas qualify for regulatory accounting treatment under applicable U.S. GAAP, similar to the California Utilities. In September 2016, we sold EnergySouth Inc., the parent company of Mobile Gas and Willmut Gas, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

The table below summarizes natural gas and electric revenue for our utilities outside of California for the nine months ended September 30, 2016 and 2015:



OTHER UTILITIES
NATURAL GAS AND ELECTRIC REVENUES
(Dollars in millions)
	Nine months ended September 30, 2016			Nine months ended September 30, 2015
	Volumes	Revenue		Volumes	Revenue
Natural Gas Sales (billion cubic feet):
Sempra Mexico – Ecogas	22	$	64	19	$	62
Sempra Natural Gas:
Mobile Gas (including transportation)(1)	33	57		35	62
Willmut Gas(1)	2	11		2	14
Total	57	$	132	56	$	138

Electric Sales (million kilowatt hours):
Sempra South American Utilities:
Luz del Sur	5,607	$	681	5,695	$	663
Chilquinta Energía	2,161	388		2,172	384
	7,768	1,069		7,867	1,047
Other service revenues		33			30
Total		$	1,102		$	1,077


(1)	EnergySouth, the parent company of Mobile Gas and Willmut Gas, was sold on September 12, 2016.

We discuss changes in electric sales and volumes for Sempra South American Utilities under “Sempra Energy Consolidated – Electric Revenues” above.

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Energy-Related Businesses: Revenues and Cost of Sales

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



ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
	Three months ended September 30,						Nine months ended September 30,
	2016			2015			2016			2015
REVENUES
Sempra South American Utilities	$	26		$	22		$	68		$	74
Sempra Mexico	174			175			417			446
Sempra Renewables	12			12			25			30
Sempra Natural Gas	152			144			316			436
Intersegment revenues, eliminations and adjustments(1)	(93		)	(85		)	(213		)	(224		)
Total revenues	$	271		$	268		$	613		$	762
COST OF SALES(2)
Cost of natural gas, electric fuel and purchased power:
Sempra South American Utilities	$	4		$	3		$	12		$	19
Sempra Mexico	76			71			151			167
Sempra Natural Gas	106			101			257			293
Eliminations and adjustments(1)	(91		)	(84		)	(207		)	(217		)
Total	$	95		$	91		$	213		$	262
Other cost of sales:
Sempra South American Utilities	$	20		$	17		$	49		$	46
Sempra Mexico	2			3			7			12
Sempra Natural Gas	12			15			243			58
Eliminations and adjustments(1)	(2		)	(1		)	(6		)	(5		)
Total	$	32		$	34		$	293		$	111


(1)	Includes eliminations of intercompany activity.


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

During the three months ended September 30, 2016, revenues from our energy-related businesses increased by $3 million (1%) to $271 million primarily due to higher revenues at Sempra Natural Gas, offset by higher intercompany eliminations between Sempra Natural Gas and Sempra Mexico.

During the three months ended September 30, 2016, the cost of natural gas, electric fuel and purchased power for our energy-related businesses increased by $4 million (4%) to $95 million primarily due to:


▪	$5 million increase at Sempra Natural Gas primarily due to higher natural gas volumes; and


▪	$5 million increase at Sempra Mexico primarily due to higher natural gas volumes; offset by


▪	$7 million primarily from higher intercompany eliminations of costs associated with sales between Sempra Natural Gas and Sempra Mexico.

For the first nine months of 2016, revenues from our energy-related businesses decreased by $149 million (20%) to $613 million. The decrease included


▪	$120 million decrease at Sempra Natural Gas associated with midstream and LNG marketing activities, including:


◦	$75 million primarily driven by changes in natural gas prices and lower volumes,


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


◦	$11 million from lower natural gas sales to Sempra Mexico;


▪	$29 million lower revenues at Sempra Mexico primarily due to lower power volumes and prices in its power business, including $25 million decrease at the TdM power plant; and


▪	$6 million lower revenues at Sempra South American Utilities primarily due to foreign currency exchange rate effects; offset by


▪	$11 million from lower intercompany eliminations associated with sales between Sempra Natural Gas and Sempra Mexico.

For the first nine months of 2016, the cost of natural gas, electric fuel and purchased power for our energy-related businesses decreased by $49 million (19%) to $213 million primarily due to:


▪	$36 million decrease at Sempra Natural Gas primarily due to lower natural gas costs and lower electric fuel costs due to the sale of the remaining block of Mesquite Power in April 2015; and

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▪	$16 million decrease at Sempra Mexico primarily due to lower natural gas costs; offset by


▪	$10 million from lower intercompany eliminations of costs associated with sales between Sempra Natural Gas and Sempra Mexico.

During the first nine months of 2016, other cost of sales increased by $182 million to $293 million primarily due to $206 million related to Sempra Natural Gas’ permanent release of pipeline capacity in the second quarter of 2016, offset by $22 million of capacity costs in 2015 on the Rockies Express pipeline.

Operation and Maintenance

Sempra Energy Consolidated

Our operation and maintenance expenses increased by $2 million to $703 million in the three months ended September 30, 2016 and by $37 million (2%), remaining at $2.1 billion, in the first nine months of 2016.

SDG&E

For the three months ended September 30, 2016, SDG&E’s operation and maintenance expenses increased by $17 million (7%) to $268 million primarily due to:


▪	$24 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 litigation expense, $3 million of which is non-refundable.

In the first nine months of 2016, SDG&E’s operation and maintenance expenses increased by $57 million (8%) to $780 million primarily due to:


▪	$48 million higher expenses associated with CPUC-authorized refundable programs, for which all costs incurred are fully recovered in revenue (refundable program expenses);


▪	$12 million higher non-refundable operating costs, including labor, contract services and administrative and support costs; and


▪	$10 million at Otay Mesa VIE primarily due to major maintenance at the Otay Mesa Energy Center (OMEC) plant in the second quarter of 2016; offset by


▪	$11 million lower litigation expense, $8 million of which is non-refundable.

SoCalGas

For the three months ended September 30, 2016, SoCalGas’ operation and maintenance expenses decreased by $3 million (1%) to $322 million primarily due to:


▪	$20 million lower non-refundable operating costs, including labor, contract services and administrative and support costs; offset by


▪	$17 million higher expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses).

In the first nine months of 2016, SoCalGas’ operation and maintenance expenses decreased by $19 million (2%) to $966 million primarily due to:


▪	$13 million lower non-refundable operating costs, including labor, contract services and administrative and support costs; and


▪	$12 million lower expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses); offset by


▪	$6 million from the favorable resolution of a legal settlement in 2015.

Impairment Losses

In the third quarter of 2016, Sempra Mexico reduced the carrying value of TdM by recognizing a noncash impairment charge of $131 million ($90 million after tax and noncontrolling interests). We discuss deferred income tax impacts related to TdM and this impairment in Note 3 of the Notes to Condensed Consolidated Financial Statements herein. In the first nine months of 2016, SoCalGas recorded a $22 million ($13 million after-tax) impairment of assets related to the Southern Gas System Reliability project.

Plant Closure Adjustment

In the first quarter of 2015, SDG&E recorded a $21 million pretax reduction to the loss from plant closure. We discuss SONGS further in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.

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Gain on Sale of Assets

In the third quarter of 2016, Sempra Natural Gas completed the sale of EnergySouth for proceeds of $318 million, net of $2 million cash sold, resulting in a pretax gain of $130 million ($78 million after-tax). In the second quarter of 2015, Sempra Natural Gas completed the sale of the remaining 625-MW block of the Mesquite Power plant for net cash proceeds of $347 million, resulting in a pretax gain on sale of the asset of $61 million ($36 million after-tax).

Equity Earnings, Before Income Tax

Equity earnings, before income tax, for the three months and nine months ended September 30, 2016 decreased by $21 million and $75 million, respectively. The decrease in the three-month period was primarily due to $22 million lower equity earnings from Sempra Natural Gas’ investment in Rockies Express, which was sold in May 2016. The change in the nine-month period was primarily due to a $44 million ($27 million after-tax) impairment charge in the first quarter of 2016 and $36 million lower equity earnings from Rockies Express. We discuss the impairment charge and sale further in Notes 3 and 8 of the Notes to Condensed Consolidated Financial Statements herein.

Remeasurement of Equity Method Investment

In the third quarter of 2016, Sempra Mexico recorded a $617 million noncash gain ($350 million after tax and noncontrolling interests) associated with the remeasurement of its equity interest in GdC. We discuss the transaction further in Notes 3 and 8 of the Notes to Condensed Consolidated Financial Statements herein.

Income Taxes

The table below shows the income tax expense (benefit) and effective income tax rates for Sempra Energy, SDG&E and SoCalGas.



INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Income tax expense		Effective income tax rate		Income tax expense (benefit)			Effective income tax rate
	Three months ended September 30,
	2016				2015
Sempra Energy Consolidated	$	282	29	%	$	15		6	%
SDG&E	91		32		75			29
SoCalGas	21		100		(20		)	71

	Nine months ended September 30,
	2016				2015
Sempra Energy Consolidated	$	284	21	%	$	276		22	%
SDG&E	204		33		217			32
SoCalGas	75		27		91			25

Sempra Energy Consolidated

The increase in income tax expense in the three months ended September 30, 2016 compared to the same period in 2015 was primarily due to higher pretax income, and a higher effective income tax rate. The higher effective income tax rate was primarily due to:


▪	$17 million lower income tax benefit in 2016 primarily from transactional effects from foreign currency and inflation;


▪	$14 million income tax expense in 2016 from lower actual repairs deductions at SDG&E and SoCalGas taken on the 2015 tax return compared to amounts estimated in 2015, as we discuss in Note 10 of the Condensed Consolidated Financial Statements herein;


▪	$13 million lower income tax benefit in 2016 from the resolution of prior years’ income tax items; and


▪	$11 million higher U.S. income tax expense in 2016 primarily due to a reduction in 2015 in forecasted planned repatriation of full year 2015 earnings from certain non-U.S. subsidiaries; offset by

▪

$31 million reduction in deferred Mexican income tax liability in 2016 on the difference in the financial and tax bases of TdM due to impairment of the asset held for sale. This reduction offsets the deferred Mexican income tax expense of $32 million that was recorded in the six months ended June 30, 2016 as a result of the classification of the asset as held for sale. We discuss these matters further in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

The increase in income tax expense in the nine months ended September 30, 2016 compared to the same period in 2015 was primarily due to higher pretax income, offset by a lower effective tax rate. The lower effective tax rate was primarily due to:


▪	$34 million income tax benefit associated with the adoption of a new accounting standard related to share-based compensation; and

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▪	$5 million lower U.S. income tax expense in 2016 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries; offset by


▪	$20 million lower income tax benefit in 2016 from the resolution of prior years’ income tax items; and


▪	$14 million income tax expense in 2016 from lower actual repairs deductions at SDG&E and SoCalGas taken on the 2015 tax return compared to amounts estimated in 2015.

SDG&E

The increase in SDG&E’s income tax expense in the three months ended September 30, 2016 compared to the same period in 2015 was primarily due to higher pretax income and a higher effective income tax rate. The higher effective income tax rate was primarily due to $4 million lower income tax benefit in 2016 from the resolution of prior years’ income tax items, including $3 million income tax expense in 2016 from lower actual repairs deductions taken on the 2015 tax return compared to amounts estimated in 2015.

The decrease in SDG&E’s income tax expense in the nine months ended September 30, 2016 compared to the same period in 2015 was primarily due to lower pretax income, offset by a higher effective income tax rate. Pretax income in 2016 includes the charges associated with prior years’ tax repairs deductions as a result of the 2016 GRC FD. The higher effective income tax rate was primarily due to:


▪	$14 million lower income tax benefit in 2016 from the resolution of prior years’ income tax items, including $3 million income tax expense in 2016 from lower actual repairs deductions taken on the 2015 tax return compared to amounts estimated in 2015; offset by


▪	$7 million income tax benefit associated with the adoption of a new accounting standard related to share-based compensation.

SoCalGas

SoCalGas’ income tax expense in the three months ended September 30, 2016 compared to the income tax benefit in the same period in 2015 was primarily due to pretax income in the three months ended September 30, 2016 compared to pretax loss in the same period in 2015. SoCalGas’ income tax expense and effective income tax rate in the three months ended September 30, 2016 compared to the same period in 2015 were also impacted by $21 million lower income tax benefit in 2016 from the resolution of prior years’ income tax items, including $11 million income tax expense in 2016 from lower actual repairs deductions taken on the 2015 tax return compared to amounts estimated in 2015.

The decrease in SoCalGas’ income tax expense in the nine months ended September 30, 2016 compared to the same period in 2015 was primarily due to lower pretax income, offset by a higher effective income tax rate. Pretax income in 2016 includes the charges associated with prior years’ tax repairs deductions as a result of the 2016 GRC FD. The higher effective income tax rate was primarily due to:


▪	$24 million lower income tax benefit in 2016 from the resolution of prior years’ income tax items, including $11 million income tax expense in 2016 from lower actual repairs deductions taken on the 2015 tax return compared to amounts estimated in 2015; offset by


▪	$4 million income tax benefit associated with the adoption of a new accounting standard related to share-based compensation.

We discuss the forecasted effective tax rates anticipated for the full year, excluding the income tax effects that cannot be reliably forecasted, for Sempra Energy, SDG&E and SoCalGas in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report. 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 5 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.

Currently, the Peruvian corporate income tax rate is 28 percent, which is set to gradually decrease to 26 percent by 2019 and beyond pursuant to tax reform legislation passed in December 2014. A new administration has submitted a bill to congress that would reverse the 2014 legislation, return to a 30 percent income tax rate and decrease the dividend withholding tax rate. If enacted, the increase to the Peruvian corporate income tax rate would require us to remeasure our Peruvian deferred income tax balances, which would result in $19 million of deferred tax expense in the period when the decree is enacted. There would be no immediate impact from the decrease in the Peruvian dividend withholding tax rate, because the withholding tax will be accrued at the shareholder level when Peruvian earnings are actually distributed. We discuss the impact of tax reform in Peru further in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report.

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Earnings Attributable to Noncontrolling Interests

Earnings attributable to noncontrolling interests increased by $63 million in the three months ended September 30, 2016, primarily at IEnova due to their proportional interest in net income, as follows:


▪	$82 million gain associated with the remeasurement of our equity interest in GdC; and


▪	$6 million reduction in deferred income tax liability related to the impairment in carrying value of TdM’s assets; offset by


▪	$21 million impairment of TdM assets held for sale.

The increase in earnings attributable to noncontrolling interests of $39 million in the nine months ended September 30, 2016 includes a $60 million increase at IEnova primarily due to the remeasurement gain associated with the acquisition of GdC, net of the impairment of TdM’s assets, as discussed above for the quarterly period, offset by a $21 million decrease at SDG&E, as we discuss below.

SDG&E

Earnings attributable to noncontrolling interests decreased by $21 million in the nine months ended September 30, 2016 primarily due to an increase in operating expenses as a result of major maintenance at the OMEC plant in the second quarter of 2016.

Earnings

We discuss variations in earnings by segment above in “Segment Results.”

Impact of Foreign Currency and Inflation Rates on Results of Operations

Foreign Currency Translation

Our operations in South America and our natural gas distribution utility in Mexico use their local currency as their functional currency. The assets and liabilities of these foreign operations are translated into U.S. dollars at current exchange rates at the end of the reporting period, and revenues and expenses are translated at average exchange rates for the reporting period. The resulting noncash translation adjustments do not enter into the calculation of earnings or retained earnings, but are reflected in Other Comprehensive Income (Loss) (OCI) and in Accumulated Other Comprehensive Income (Loss) (AOCI). However, any difference in average exchange rates used for the translation of income statement activity from year to year can cause a variance in Sempra Energy’s comparative results of operations. Changes in foreign currency translation rates between years impacted our comparative reported results as follows:



TRANSLATION IMPACT FROM CHANGE IN AVERAGE FOREIGN CURRENCY EXCHANGE RATES
(Dollars in millions)
	Third quarter 2016 compared to third quarter 2015			Year-to-date 2016 compared to year-to-date 2015
Lower earnings from foreign currency translation:
Sempra South American Utilities	$	(1	)	$	8
Sempra Mexico	1			3
Total	$	—		$	11

Transactional Impacts

Some income statement activities at our foreign operations and their joint ventures are also impacted by transactional gains and losses, which we discuss below. A summary of these foreign currency transactional gains and losses included in our reported results is as follows:

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TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION
(Dollars in millions)
	Total reported amounts				Transactional (losses) gains included in reported amounts
	Three months ended September 30,
	2016		2015		2016			2015
Other income, net	$	26	$	12	$	(13	)	$	(7	)
Income tax expense	282		15		4			20
Equity earnings, net of income tax	19		27		3			7
Earnings	622		248		(2		)	17
	Nine months ended September 30,
	2016		2015		2016			2015
Other income, net	$	98	$	88	$	(32	)	$	(13	)
Income tax expense	284		276		28			33
Equity earnings, net of income tax	69		64		21			13
Earnings	991		980		18			28

Foreign Currency Exchange Rate and Inflation Impacts on Income Taxes and Related Hedging Activity. Our Mexican subsidiaries 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 that 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. As a result, fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar and Mexican inflation may expose us to fluctuations in Income Tax Expense and Equity Earnings, Net of Income Tax. We utilize short-term foreign currency derivatives as a means to manage these exposures. The derivative activity impacts Other Income, Net.

The income tax expense of our South American subsidiaries is similarly impacted by these factors.

Other Transactions. Although the financial statements of our Mexican subsidiaries and joint ventures (Ductos y Energéticos del Norte, or DEN, Energía Sierra Juárez and Infraestructura Marina del Golfo (IMG)) have the U.S. dollar as the functional currency, some transactions may be denominated in the local currency; such transactions are remeasured into U.S. dollars. This remeasurement creates transactional gains and losses that are included in Other Income, Net, for our consolidated subsidiaries and Equity Earnings, Net of Income Tax, for our joint ventures (including GdC until September 26, 2016).

We utilize cross-currency swaps that 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. The impacts of these cross-currency swaps are offset in OCI and are reclassified from AOCI into earnings through Interest Expense as settlements occur.

Certain of our Mexican pipeline projects (namely Los Ramones I at GdC and Los Ramones Norte within our DEN joint venture) generate revenue based on tariffs that are set by government agencies in Mexico, with contracts denominated in Mexican pesos that are indexed to the U.S. dollar, adjusted annually for inflation and fluctuation in the exchange rate. The resultant gains and losses from remeasuring the local currency amounts into U.S. dollars are included in Revenues: Energy-Related Businesses or Equity Earnings, Net of Income Tax. The activity of foreign currency forwards and swaps related to these contracts settle through Revenues: Energy-Related Businesses or Equity Earnings, Net of Income Tax.

Our joint ventures in Chile (Eletrans S.A. and Eletrans II S.A., collectively Eletrans) use the U.S. dollar as the functional currency, but have certain construction commitments that are denominated in the Chilean Unidad de Fomento (CLF). Eletrans entered into forward exchange contracts to manage the foreign currency exchange risk of the CLF relative to the U.S. dollar. The forward exchange contracts settle based on anticipated payments to vendors, generally monthly, ending in 2018, with activity recorded in Equity Earnings, Net of Income Tax.

CAPITAL RESOURCES AND LIQUIDITY

We expect our cash flows from operations to fund a substantial portion of our capital expenditures and dividends. We may also meet our cash requirements through the issuance of securities, bank borrowings, distributions from our equity investments and project financing.

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Our lines of credit provide liquidity and support commercial paper. As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein, Sempra Energy, Sempra Global (the holding company for our subsidiaries not subject to California utility regulation) and the California Utilities each have five-year revolving credit facilities, expiring in 2020. The agreements are syndicated broadly among 21 different lenders. No single lender has greater than a 7-percent share in any agreement. The table below shows the amount of available funds, including available unused credit on these three credit facilities, at September 30, 2016. Our foreign operations have additional general purpose credit facilities aggregating $1.1 billion, with $429 million available unused credit at September 30, 2016.



AVAILABLE FUNDS AT SEPTEMBER 30, 2016
(Dollars in millions)
	Sempra Energy Consolidated		SDG&E		SoCalGas
Unrestricted cash and cash equivalents(1)	$	518	$	23	$	8
Available unused credit(2)	2,025		696		750


(1)	Amounts at Sempra Energy Consolidated include $474 million held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated.


(2)	Available credit is the total available on Sempra Energy’s, Sempra Global’s and the California Utilities’ credit facilities that we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein. At September 30, 2016, borrowings on the shared line of credit at SDG&E and SoCalGas were limited to $750 million for each utility and a combined total of $1 billion.

Sempra Energy Consolidated

We believe that these available funds, combined with cash flows from operations, distributions from equity method investments, proceeds of securities issuances, project financing and partnering in joint ventures will be adequate to fund operations, including to:


▪	finance capital expenditures


▪	meet liquidity requirements


▪	fund shareholder dividends


▪	fund new business acquisitions or start-ups


▪	repay maturing long-term debt


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

The net increase in Sempra Energy Consolidated cash and cash equivalents of $115 million at September 30, 2016 compared to December 31, 2015 was primarily due to net increases in publicly traded debt securities and commercial paper borrowings supported by the Sempra Global and California Utilities credit facilities, as well as proceeds received from the sale of our 25-percent interest in Rockies Express and the sale of EnergySouth, partially offset by our acquisition of GdC, capital expenditures, cash outflows related to the natural gas leak at the Aliso Canyon facility, and common dividends paid. We discuss our Insurance Receivable and our insurance coverage related to the natural gas leak at the Aliso Canyon facility in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

On October 19, 2016, IEnova received approximately $1.57 billion in net proceeds from an international private offering and its concurrent public offering in Mexico of IEnova’s common stock, as we discuss in Note 13 of the Notes to Condensed Consolidated Financial Statements herein, of which $1.150 billion was used to repay bridge financing provided by commercial paper borrowings at Sempra Global. The net proceeds include Sempra Energy’s participation in the offering by the purchase of approximately $351 million of the common stock. In addition, we anticipate significant cash activity in the fourth quarter of 2016 to include


▪	approximately $400 million cash outlay for IEnova’s pending acquisition of the Ventika I and Ventika II (collectively, Ventika) wind power generation facilities, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein


▪	approximately $1.6 billion cash outlay for other capital expenditures and investments


▪	$390 million to $410 million of proceeds from tax equity funding of certain of Sempra Renewables’ wind and solar generation projects


▪	$500 million debt issuance at Sempra Energy in October, as we discuss below

In October 2016, Sempra Energy issued $500 million of 1.625-percent notes maturing in 2019. In May 2016, SDG&E issued $500 million of 2.50-percent first mortgage bonds maturing in 2026. In June 2016, SoCalGas issued $500 million of 2.60-percent first mortgage bonds, also maturing in 2026. In 2015, Sempra Energy, SDG&E and SoCalGas publicly offered and sold debt securities totaling $1.25 billion, $390 million and $600 million, respectively. 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 could 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 and alternative sources of funding at Sempra International and Sempra U.S. Gas & Power. If cash flows from operations were to be significantly reduced or we were unable

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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 certain of our Sempra International and Sempra U.S. Gas & Power businesses before we would reduce funds necessary for the ongoing needs of our utilities. We monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our intention to maintain strong, investment-grade credit ratings and capital structure.

At September 30, 2016, our cash and cash equivalents held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated are $474 million. We discuss repatriation in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

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 nuclear decommissioning trusts. At the California Utilities, funding requirements are generally recoverable in rates.

We discuss our principal, general purpose credit facilities more fully in Note 6 of the Notes to Condensed Consolidated Financial Statements herein and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.

Our short-term debt is primarily used to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures and new business acquisitions or start-ups. Our corporate short-term, unsecured promissory notes, or commercial paper, were our primary sources of short-term debt funding in the first nine months of 2016. At our California Utilities, short-term debt is used to meet working capital needs and temporarily finance capital expenditures.

California Utilities

SDG&E and SoCalGas expect that available funds, cash flows from operations and debt issuances will continue to be adequate to meet their working capital and capital expenditure requirements.

SoCalGas declared no stock dividends in 2016 and declared and paid common stock dividends of $50 million in 2015 and $100 million in 2014. As a result of an increase in SoCalGas’ capital investment programs over the next few years, and the increase in SoCalGas’ authorized common equity weighting effective January 1, 2013, SoCalGas’ dividends on common stock declared on an annual historical basis may not be indicative of future declarations, and may be temporarily suspended over the next few years to maintain SoCalGas’ authorized capital structure during the periods of high capital investments. We discuss the cost of capital proceeding in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

In connection with the natural gas leak at the Aliso Canyon storage facility, as of November 1, 2016, 212 lawsuits, including over 12,000 plaintiffs, have been filed against SoCalGas, some of which have also named Sempra Energy. Derivative and securities claims have also been filed on behalf of Sempra Energy and/or SoCalGas shareholders against certain officers and directors of Sempra Energy and/or SoCalGas. All of these cases, other than the derivative actions, the federal securities class action and a matter brought by the Los Angeles County District Attorney discussed below, are coordinated before a single court in the Los Angeles County Superior Court for pretrial management. Pursuant to the parties’ agreement, the court ordered that the individual and business entity plaintiffs (other than a Proposition 65 case, the federal securities class action and the shareholder derivative cases) would proceed by filing consolidated master complaints. We provide further detail on these master complaints and the derivative and securities cases, as well as complaints filed by the California Attorney General, acting in her independent capacity and on behalf of the people of the State of California and the California Air Resources Board (CARB), together with the Los Angeles City Attorney; the South Coast Air Quality Management District (SCAQMD); and the County of Los Angeles, on behalf of itself and the people of the State of California, in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

Separately, on February 2, 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. On February 16, 2016, SoCalGas pled not guilty to the complaint. On September 13, 2016, SoCalGas entered a plea of 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 $232,500, and up to $4 million in operational commitments, reimbursement and assessments in exchange for the District Attorney’s Office moving to dismiss the remaining counts at sentencing and settling the complaint. The sentencing hearing is currently scheduled for November 29, 2016, at which we expect the court to rule on the motion to dismiss and determine whether to enter judgment on the notice count pursuant to the plea agreement. On October 18, 2016, certain plaintiffs in the separate civil cases filed a “Victims’ Request for Withdrawal of Plea Agreement” with the court. We provide further detail regarding this proceeding in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

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The costs of defending against these civil and criminal lawsuits and cooperating with these 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, 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 could be significant and may not be recoverable in customer rates, which may have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations, cash flows, and financial condition.

On May 13, 2016, the Los Angeles County Department of Public Health (DPH) issued a directive that SoCalGas 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 have experienced symptoms from the natural gas leak (the Directive). SoCalGas contends that the Directive is invalid and unenforceable, and has filed a petition for writ of mandate to set aside the Directive.

We discuss the Aliso Canyon facility further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein, and in “Factors Influencing Future Performance” below.

In May 2016, SDG&E declared common stock dividends of $175 million, which were paid on July 6, 2016. SDG&E declared and paid common stock dividends of $300 million in 2015 and $200 million in 2014. SDG&E expects to continue paying common dividends over the next five years, at or above the level paid in 2015. While it expects to maintain a large capital program (exceeding $1 billion per year), SDG&E expects that its cash flows will support these dividends to the parent.

Changes in balancing accounts for significant costs at SDG&E and SoCalGas, particularly a change in status between over- and under- collected, 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 uses the Energy Resource Recovery Account (ERRA) balancing account to record the net of its actual cost incurred for electric fuel and purchased power. SDG&E’s ERRA balance was undercollected by $70 million at September 30, 2016 and overcollected by $25 million at December 31, 2015. During the first nine months of 2016, the ERRA undercollected balance was primarily caused by actual volumes being lower than authorized sales in 2016.

SoCalGas and SDG&E use the Core Fixed Cost Account (CFCA) balancing account to record the difference between the authorized margin and other costs allocated to core customers. Because warmer weather experienced in 2014 and 2015 resulted in lower natural gas consumption compared to authorized levels, SoCalGas’ CFCA balance was undercollected by $147 million at September 30, 2016 and $328 million at December 31, 2015. SDG&E’s CFCA balance was undercollected by $63 million at September 30, 2016 and $105 million at December 31, 2015.

Sempra South American Utilities

We expect working capital and capital expenditure requirements, projects, joint venture investments, and loans to affiliates at Chilquinta Energía and Luz del Sur to be funded by available funds, funds internally generated by those businesses, issuance of corporate bonds and other external borrowings. At September 30, 2016 and December 31, 2015, Sempra South American Utilities had outstanding loans of $83 million and $72 million, respectively, to an affiliate to finance development projects. We discuss these loans in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Mexico

We expect working capital and capital expenditure requirements, projects, joint venture investments and dividends in Mexico to be funded by available funds, including credit facilities, and funds internally generated by the Mexico businesses, securities issuances, project financing, interim funding from the parent, and partnering in joint ventures.

In October 2016, Sempra Mexico received net proceeds of approximately $1.57 billion from the sale of IEnova common stock in an international private offering and concurrent public offering in Mexico, as we discuss above and in Note 13 of the Notes to Condensed Consolidated Financial Statements herein. IEnova used the net proceeds of the offerings to repay the $1.150 billion bridge loan from Sempra Global that was used to finance the GdC acquisition and expects to use a part of the proceeds to partially fund the acquisition of Ventika in the fourth quarter of 2016. We discuss these acquisitions in Note 3 of the Notes to Condensed Consolidated Financial Statements herein. The remaining proceeds will be used to fund capital expenditures and for general corporate purposes.

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In August 2016, Sempra Mexico paid dividends of $26 million to its minority shareholders. In 2015 and 2014, Sempra Mexico paid dividends of $32 million and $31 million, respectively.

At September 30, 2016 and December 31, 2015, Sempra Mexico had outstanding loans of $103 million and $111 million, respectively, to unconsolidated affiliates to fund development projects. We discuss these loans in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Mexico also may generate cash from the sale of its 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein, in February 2016, management approved a plan to market and sell the plant, which had a net book value of $146 million (including associated assets and liabilities) at September 30, 2016.

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. In July 2016, Sempra Renewables received a $78 million cash deposit from a financial institution to fund portfolio tax equity partnerships, which include Copper Mountain Solar 4, Mesquite Solar 2 and Mesquite Solar 3. Sempra Renewables expects the final funding date and formation of the portfolio tax equity partnerships, which include the Black Oak Getty Wind project, to occur in the fourth quarter of 2016, with additional tax equity funding of approximately $390 million to $410 million. These projects have planned in-service dates through 2017.

Sempra Natural Gas

We expect Sempra Natural Gas 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 and project financing. In May 2016, Sempra Natural Gas received $443 million net proceeds from the sale of its investment in Rockies Express. In September 2016, Sempra Natural Gas received $318 million net proceeds from the sale of EnergySouth Inc. and the buyer assumed $67 million of debt, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein. In the short-term, we plan to use the sale proceeds from these transactions to pay down commercial paper at Sempra Energy, pending redeployment for other growth opportunities.

Sempra Natural Gas, through Cameron LNG JV, is developing a natural gas liquefaction export facility at the Cameron LNG JV terminal. The majority of the 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. Under the financing agreements, Sempra Energy signed completion guarantees for 50.2 percent of the debt, which corresponds to $3.7 billion of the total $7.4 billion principal amount of the debt committed under the financing agreements. The project financing and completion guarantees became effective on October 1, 2014, the effective date of the joint venture formation. The completion guarantees will terminate upon satisfaction of certain conditions, including all three trains achieving commercial operation and meeting certain operational performance tests. The completion guarantees are anticipated to be terminated approximately nine months after all three trains achieve commercial operation.

We discuss Cameron LNG JV and the joint venture financing further in Notes 3 and 4 of the Notes to Consolidated Financial Statements in the Annual Report, and we discuss the status of the project below in “Factors Influencing Future Performance – Sempra Natural Gas – Cameron Liquefaction.”

CASH FLOWS FROM OPERATING ACTIVITIES



CASH PROVIDED BY OPERATING ACTIVITIES
(Dollars in millions)
	Nine months ended September 30, 2016		2016 change					Nine months ended September 30, 2015
Sempra Energy Consolidated	$	1,691	$	(398	)	(19	)%	$	2,089
SDG&E	933		(161		)	(15	)	1,094
SoCalGas	409		(281		)	(41	)	690

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Sempra Energy Consolidated

Cash provided by operating activities at Sempra Energy decreased in 2016 primarily due to:


▪	$339 million increase in receivable at SoCalGas for expected insurance recovery of certain expenditures related to the natural gas leak at the Aliso Canyon storage facility, and a $201 million net decrease in reserve for accrued expenditures related to the leak. The $201 million net decrease includes $597 million of cash expenditures, offset by $396 million of additional accruals;

▪

$274 million lower net income, adjusted for noncash items included in earnings, in 2016 compared to 2015, including charges for income tax benefits previously generated from income tax repairs deductions that were reallocated to ratepayers pursuant to the 2016 GRC FD, as well as lower results at Sempra Natural Gas driven by changes in natural gas prices, as we discuss in “Results of Operations” above; and


▪	$66 million higher income tax payments in 2016; offset by


▪	$92 million increase in accounts payable in 2016 compared to a $130 million decrease in 2015, primarily due to the current moratorium on natural gas injections at the Aliso Canyon storage facility as well as lower average cost of natural gas purchased;


▪	$269 million decrease in accounts receivable in 2016 compared to a $145 million decrease in 2015, primarily due to lower electric consumption at SDG&E in 2016;

▪

$259 million net increase in overcollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2016 at the California Utilities compared to a $182 million net decrease in undercollected regulatory balancing accounts in 2015. Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time. See further discussion of changes in regulatory balances at both SDG&E and SoCalGas below; and


▪	$23 million reduction to the SONGS regulatory asset due to cash received for our portion of the Department of Energy settlement with Southern California Edison related to spent fuel storage, as we discuss in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

SDG&E

Cash provided by operating activities at SDG&E decreased in 2016 primarily due to:


▪	$20 million decrease in net undercollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2016 compared to a $244 million decrease in 2015, primarily due to changes in electric commodity accounts;


▪	$103 million higher income tax payments in 2016; and


▪	$78 million lower net income, adjusted for noncash items included in earnings, in 2016 compared to 2015; offset by


▪	$30 million increase in accounts receivable in 2016 compared to a $136 million increase in 2015, primarily due to lower electric consumption in 2016;


▪	$40 million increase in greenhouse gas allowances in 2016 compared to a $93 million increase in 2015;


▪	$95 million increase in accounts payable in 2016 compared to a $57 million increase in 2015; and


▪	$23 million reduction to the SONGS regulatory asset due to cash received for our portion of the Department of Energy settlement with Southern California Edison related to spent fuel storage, as we discuss in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

SoCalGas

Cash provided by operating activities at SoCalGas decreased in 2016 primarily due to:


▪	$339 million increase in receivable for expected insurance recovery of certain expenditures related to the natural gas leak at the Aliso Canyon storage facility, and a $201 million net decrease in reserve for accrued expenditures related to the leak. The $201 million net decrease includes $597 million of cash expenditures, offset by $396 million of additional accruals;


▪	$92 million lower net income, adjusted for noncash items included in earnings, in 2016 compared to 2015; and


▪	$41 million decrease in accrued compensation benefits in 2016 compared to a $15 million increase in 2015; offset by


▪	$239 million increase in net overcollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2016 compared to a $62 million increase in net undercollected regulatory balancing accounts in 2015, primarily due to changes in fixed-cost balancing accounts; and


▪	$60 million decrease in accounts payable in 2016 compared to a $191 million decrease in 2015, primarily due to the current moratorium on natural gas injections at the Aliso Canyon storage facility, as well as lower average cost of natural gas purchased.

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The table below shows the contributions to pension and other postretirement benefit plans.



CONTRIBUTIONS TO PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
	Nine months ended September 30, 2016
	Pension plans		Other postretirement benefit plans
Sempra Energy Consolidated	$	24	$	3
SDG&E	2		—
SoCalGas	1		1

CASH FLOWS FROM INVESTING ACTIVITIES



CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
	Nine months ended September 30, 2016			2016 change					Nine months ended September 30, 2015
Sempra Energy Consolidated	$	(3,432	)	$	1,453		73	%	$	(1,979	)
SDG&E	(982		)	172			21	%	(810		)
SoCalGas	(950		)	(246		)	(21	)%	(1,196		)

Sempra Energy Consolidated

Cash used in investing activities at Sempra Energy increased in 2016 primarily due to:


▪	$1.078 billion, net of cash acquired, for Sempra Mexico’s acquisition of the remaining 50-percent interest in GdC in September 2016;


▪	$860 million increase in capital expenditures;


▪	in 2015, $347 million of net proceeds received from Sempra Natural Gas’ sale of the remaining block of its Mesquite Power plant; and


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


▪	$443 million net proceeds received from Sempra Natural Gas’ sale of its investment in Rockies Express in May 2016;


▪	$318 million net proceeds from Sempra Natural Gas’ sale of EnergySouth in September 2016; and


▪	in 2015, $113 million investment in Rockies Express to repay project debt.

SDG&E

Cash used in investing activities at SDG&E increased in 2016 primarily due to:


▪	$124 million increase in capital expenditures; and


▪	$107 million advances to Sempra Energy in 2016; offset by


▪	$71 million decrease in Nuclear Decommissioning Trust in 2016 as a result of CPUC authorization to withdraw trust funds for SONGS decommissioning costs incurred in 2013 and 2014, compared to a $37 million withdrawal in 2015 for costs incurred in 2013.

SoCalGas

Cash used in investing activities at SoCalGas decreased in 2016 primarily due to a $250 million advance to Sempra Energy in 2015.

ANNUAL CONSTRUCTION EXPENDITURES AND INVESTMENTS

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 Federal Energy Regulatory Commission (FERC). However, in 2016, we expect to make capital expenditures and investments of approximately $6.3 billion. These expenditures include


▪	$2.8 billion at the California Utilities for capital projects and plant improvements ($1.4 billion at SDG&E and $1.4 billion at SoCalGas), excluding incremental amounts that may result from the natural gas leak at the Aliso Canyon facility or related increased requirements for all natural gas storage facilities

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▪	$3.5 billion at our other subsidiaries for acquisition of our joint venture partner’s 50-percent interest in GdC and for the acquisition of Ventika wind-generation facilities, capital projects in Mexico and South America, and development of LNG, natural gas and renewable generation projects

The California Utilities’ 2016 planned capital expenditures and investments include

SDG&E


▪	$900 million for improvements to natural gas, including pipeline safety, and electric generation and distribution systems


▪	$500 million for improvements to electric transmission systems

SoCalGas


▪	$1.2 billion for improvements to distribution, transmission and storage systems, and for pipeline safety, including $360 million for the PSEP


▪	$100 million for advanced metering infrastructure


▪	$100 million for other natural gas projects

In 2016, the expected capital expenditures and investments of approximately $3.5 billion at our other subsidiaries include

Sempra South American Utilities


▪	approximately $210 million for capital projects in South America (approximately $160 million and $50 million in Peru and Chile, respectively), primarily related to improvements to electric transmission and distribution systems

Sempra Mexico

▪

approximately $475 million to $525 million for capital projects, including approximately $400 million for the development of the Sonora, Ojinaga and San Isidro – Samalayuca pipeline projects, all developed solely by Sempra Mexico, and approximately $80 million current year equity investment in the Infraestructura Marina del Golfo (IMG) joint venture for the development of the South Texas – Tuxpan pipeline


▪	$1.1 billion for the acquisition of our joint venture partner’s 50-percent interest in GdC and approximately $400 million for the acquisition of Ventika I and Ventika II wind-generation facilities, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein

Sempra Renewables


▪	approximately $1.0 billion for the development of wind and solar renewable projects, including $950 million for Black Oak Getty Wind, Mesquite Solar 2, Mesquite Solar 3, Copper Mountain Solar 4 and Apple Blossom Wind

Sempra Natural Gas


▪	approximately $160 million for development of LNG and natural gas transportation projects, including approximately $50 million capitalized interest on our investment in the Cameron LNG JV, and $70 million for development of the Cameron Interstate Pipeline

Capital expenditure amounts include capitalized interest. At the California Utilities, the amounts also include the portion of allowance for funds used during construction (AFUDC) related to debt, but exclude the portion of AFUDC related to equity. At Sempra Mexico and Sempra Natural Gas, the amounts also exclude AFUDC related to equity. We provide further details about AFUDC in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

CASH FLOWS FROM FINANCING ACTIVITIES



CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
	Nine months ended September 30, 2016		2016 Change			Nine months ended September 30, 2015
Sempra Energy Consolidated	$	1,848	$	1,819		$	29
SDG&E	52		324			(272		)
SoCalGas	491		(53		)	544

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Sempra Energy Consolidated

At Sempra Energy, cash provided by financing activities increased in 2016, primarily due to:


▪	$1,636 million increase in short-term debt in 2016 compared to a $201 million decrease in 2015; and


▪	$78 million deposit received by Sempra Renewables in connection with a tax equity financing arrangement expected to close in the fourth quarter of 2016; offset by

▪

$56 million from excess tax benefits related to share-based compensation in 2015. In connection with the adoption of a new accounting standard related to share-based compensation, discussed in Note 2 of the Notes to Condensed Consolidated Financial Statements herein, $34 million of similar excess tax benefits are now recorded in earnings and included as an operating activity for the nine months ended September 30, 2016;


▪	$42 million increase in common dividends paid in 2016; and


▪	$45 million lower issuances of debt, including a decrease in issuances of long-term debt of $551 million ($1 billion in 2016 compared to $1.6 billion in 2015, partially offset by an increase in commercial paper and other short-term debt borrowings with maturities greater than 90 days of $506 million ($966 million in 2016 compared to $460 million in 2015).

SDG&E

At SDG&E, financing activities were a net source of cash in 2016 compared to a use of cash in 2015, primarily due to:


▪	$146 million lower payments of long-term debt in 2016;


▪	$110 million higher issuances of long-term debt in 2016; and


▪	$114 million decrease in short-term debt in 2016 compared to a $202 million decrease in 2015.

SoCalGas

Cash provided by financing activities at SoCalGas decreased in 2016 primarily due to $100 million lower issuances of long-term debt in 2016, partially offset by a $50 million decrease in short-term debt in 2015.

COMMITMENTS

We discuss significant changes to contractual commitments since December 31, 2015 at Sempra Energy, SDG&E and SoCalGas in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

CREDIT RATINGS

The credit ratings of Sempra Energy, SDG&E and SoCalGas remained at investment grade levels during the first nine months of 2016. Our credit ratings may affect the rates at which borrowings bear interest and of commitment fees on available unused credit. We provide additional information about our credit ratings at Sempra Energy, SDG&E and SoCalGas in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Credit Ratings” in the Annual Report.

FACTORS INFLUENCING FUTURE PERFORMANCE

CALIFORNIA UTILITIES

Overview

The California Utilities’ operations have historically provided relatively stable earnings and liquidity.

The California Utilities’ performance will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by the California legislature and the changing energy marketplace. Their performance will also depend on the successful completion of capital projects that we discuss below and in various sections of this report and in the Annual Report. In addition, SoCalGas’ performance will depend on the resolution of the legal, regulatory and other matters concerning the natural gas leak at Aliso Canyon. We discuss certain regulatory matters below and in Notes 9, 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein and Notes 13, 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

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Joint Matters

CPUC General Rate Case (GRC)

In November 2014, the California Utilities filed their 2016 General Rate Case (2016 GRC) applications to establish their authorized 2016 revenue requirements and the ratemaking mechanisms by which those requirements would change on an annual basis over the subsequent three-year (2016-2018) period. In June 2016, the CPUC approved a final decision (2016 GRC FD) in the California Utilities’ 2016 GRC, effective retroactive to January 1, 2016. The adopted revenue requirements associated with the seven-month period through July 2016 will be recovered in rates over a 17-month period, beginning August 2016. We discuss the 2016 GRC and the 2016 GRC FD in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

Natural Gas Pipeline Operations Safety Assessments

Pending the outcome of the various regulatory agency evaluations of natural gas pipeline safety regulations, practices and procedures, Sempra Energy, including the California Utilities, may incur incremental expense and capital investment associated with their natural gas pipeline operations and investments. In August 2011, the California Utilities filed implementation plans with the CPUC to test or replace natural gas transmission pipelines located in populated areas that have not been pressure tested, as we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. The California Utilities’ total estimated cost for Phase 1 (the 10-year period of 2012 to 2022) of a two-phase plan was $2.1 billion ($1.6 billion for SoCalGas and $500 million for SDG&E). We anticipate that these cost estimates may be updated to reflect the development of more detailed estimates, actual cost experience as portions of the work are completed and changes in scope. The California Utilities requested that the incremental capital investment required as a result of any approved plan be included in rate base and that cost recovery be allowed for any other incremental cost not eligible for rate-base recovery. The costs that are the subject of these plans were outside the scope of the 2012 GRC proceedings and are not included in the 2016 GRC approved revenue requirements.

In June 2014, the CPUC issued a final decision addressing SDG&E’s and SoCalGas’ PSEP that approved the utilities’ model for implementing PSEP, and established the criteria to determine the amounts related to PSEP that may be recovered from ratepayers and the processes for recovery of such amounts, including providing that such costs are subject to a reasonableness review. As a result of this decision, SoCalGas recorded an after-tax earnings charge of $5 million in 2014 for costs incurred in prior periods that were no longer subject to recovery. After taking the amounts disallowed for recovery into consideration, as of September 30, 2016, SDG&E and SoCalGas have recorded PSEP costs of $18 million and $212 million, respectively, in the CPUC-authorized regulatory account.

In July 2014, the CPUC Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN) filed a joint application for rehearing of the CPUC’s June 2014 final decision. In March 2015, the CPUC issued a decision denying the ORA’s and TURN’s second request for rehearing, but keeping the record open to admit additional evidence on the limited issue of pressure testing or replacing pipelines installed between January 1, 1956 and July 1, 1961. The ORA and TURN allege that the CPUC made a legal error in directing that ratepayers, not shareholders, be responsible for the costs associated with testing or replacing transmission pipelines that were installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. In December 2015, the CPUC issued a final decision finding that ratepayers should not bear the costs associated with pressure testing subject pipelines, or, if replaced, ratepayers should bear neither the average cost of pressure testing nor the undepreciated balance of abandoned pipelines. In January 2016, SoCalGas and SDG&E jointly filed a request with the CPUC seeking rehearing of its December 2015 decision. In May 2016, the CPUC issued a decision denying the request for rehearing. Through September 30, 2016, the after-tax disallowed costs for SoCalGas and SDG&E are $3.6 million and $0.5 million, respectively.

In October 2014, SDG&E and SoCalGas filed a petition for modification with the CPUC requesting authority to recover PSEP costs from customers as incurred, subject to refund pending the results of a reasonableness review by the CPUC, instead of recovery of such costs in a subsequent year.

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approve approximately $2 million in insurance-related costs, but allows SDG&E and SoCalGas to seek recovery at a later date. A final decision is expected in the fourth quarter of 2016.

We provide additional information regarding these rulemaking proceedings and the California Utilities’ PSEP in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report and in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.

Safety Enforcement

California Senate Bill (SB) 291 requires the CPUC to develop and implement a safety enforcement program that includes procedures for monitoring, data tracking and analysis, and investigations, as well as delegating citation authority to CPUC staff personnel under the direction of the CPUC Executive Director. In exercising the citation authority, the CPUC staff will take into account voluntary reporting of potential violations, voluntary resolution efforts undertaken, prior history of violations, the gravity of the violation and the degree of culpability. The CPUC also has implemented both electric and gas safety enforcement programs whereby electric and gas utilities may be cited by CPUC staff for violations of the CPUC’s safety requirements or federal standards.

Under each enforcement program, each day of an ongoing violation may be counted as an additional offense. The maximum penalty is $50,000 per offense. Citations under either program may be appealed to the CPUC. In September 2016, the CPUC issued a decision making further refinements to the electric and gas safety enforcement programs. The decision harmonizes the rules for the two programs, further defines the criteria for issuing a citation and penalty, sets an administrative limit of $8 million per citation issued and makes certain other changes to rules related to self-reporting and notifying local officials.

In May 2016, the CPUC’s Safety and Enforcement Division issued a citation to SoCalGas for violation of General Order 112, resulting in a $2.25 million penalty that was subsequently paid. The citation is associated with findings from two 2015 audits of SoCalGas’ Southeast Region for failure to promptly remediate corrosion issues in accordance with Federal regulations.

SDG&E Matters

2007 Wildfire Litigation

In regard to the 2007 wildfire litigation, SDG&E’s payments for claims settlements plus funds estimated to be required for settlement of outstanding claims and legal fees have exceeded its liability insurance coverage and amounts recovered from third parties. However, SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of the reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and amounts recovered from third parties. Consequently, Sempra Energy and SDG&E expect no significant earnings impact from the resolution of the remaining wildfire claims. At September 30, 2016, Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets include assets of $356 million in Other Regulatory Assets (long-term), of which $354 million relates to CPUC-regulated operations and $2 million relates to FERC-regulated operations, for costs incurred and the estimated resolution of pending claims. In September 2015, SDG&E filed an application with the CPUC requesting rate recovery of these costs, as we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements herein. SDG&E requested a CPUC decision by the end of 2016 and is proposing to recover the costs in rates over a six- to ten-year period. In April 2016, the CPUC issued a ruling establishing the scope and schedule for the proceeding, which will be managed in two phases. Phase 1 will address SDG&E’s operational and management prudence surrounding the 2007 wildfires. Phase 2 will address whether SDG&E’s actions and decision-making in connection with settling legal claims in relation to the wildfires were reasonable. In October 2016, intervening parties submitted Phase 1 testimony raising various concerns with SDG&E’s operations and management prior to and during the 2007 wildfires. Participating parties asked that the CPUC reject SDG&E’s request for cost recovery. Evidentiary hearings in Phase 1 are scheduled to be held in January 2017, with a final decision scheduled to be issued in the second half of 2017. The procedural schedule for Phase 2 will be determined after Phase 1 is concluded.

Recovery of these costs in rates will require future regulatory approval. SDG&E will continue to assess the likelihood, amount and timing of such recoveries in rates. Should SDG&E conclude that recovery of excess wildfire costs in rates is no longer probable, at that time SDG&E would record a charge against earnings. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated, at September 30, 2016, the resulting after-tax charge against earnings would have been up to approximately $210 million. A failure to obtain substantial or full recovery of these costs from customers, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s financial condition, cash flows and results of operations. We discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

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We provide additional information concerning these matters in Notes 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

SONGS

We discuss regulatory and other matters related to SONGS in Notes 9 and 11 of the Notes to Condensed Consolidated Financial Statements herein, in Notes 13 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, and in “Risk Factors” in the Annual Report.

Electric Rate Reform – California Assembly Bill 327

In October 2013, the Governor of California signed Assembly Bill (AB) 327. This bill became law on January 1, 2014. This law restores the authority to establish electric residential rates for electric utility companies in California to the CPUC and removes the rate caps established in AB 1X adopted in early 2001 during California’s energy crisis, as well as SB 695 adopted in 2009. Additionally, the bill provides the CPUC the authority to adopt up to a $10.00 monthly fixed charge for all non-CARE (California Alternate Rates for Energy) residential customers and up to a $5.00 monthly fixed charge for CARE customers. Beginning January 1, 2016, the maximum allowable fixed charge may be adjusted by no more than the annual percentage increase in the Consumer Price Index for the prior calendar year. In July 2015, the CPUC adopted a decision that establishes comprehensive reform and a framework for rates that are more transparent, fair and sustainable. The decision directs changes beginning in summer 2015 and provides a path for continued reforms through 2020, including a minimum monthly bill of $10.00 ($5.00 for CARE customers). The changes also include fewer rate tiers and a gradual reduction in the difference between the tiered rates, similar to the tier differential that existed prior to the 2000-2001 Energy Crisis. The number of tiers was reduced from four to three in 2015 and was reduced to two on July 1, 2016. The rate differential between the highest and lowest tiers was reduced from approximately 2.4 times to 2.18 times in 2015, and will reduce to 1.25 times by as early as 2019. The decision also directs the utilities to pursue expanded time of use rates and implements a high usage surcharge in 2017 for usage that exceeds average customer usage by approximately 400 percent. The decision still allows the utilities to seek a fixed charge, but sets certain conditions for its implementation, which would be no sooner than 2020. The changes implemented should result in significant rate relief for higher-use SDG&E customers who do not exceed the high usage surcharge threshold and will result in a rate structure that better aligns rates with the actual cost to serve customers.

In July 2014, the CPUC initiated a rulemaking proceeding to develop a successor tariff to the state’s existing net energy metering (NEM) program pursuant to the provisions of AB 327, which required the CPUC to establish a revised NEM tariff or similar program by December 31, 2015. The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable generation. It was originally established in California in 1995 with the adoption of SB 656, as codified in Section 2827 of the Public Utilities Code. Currently, customers who install and operate eligible renewable generation facilities of one megawatt or less may choose to participate in the NEM program. Under NEM, customer-generators receive a full retail-rate for the energy they generate that is fed back to the utility’s power grid. This occurs during times when the customer’s generation exceeds their own energy usage. In addition, if a NEM customer generates any electricity over the annual measurement period that exceeds their annual consumption, they receive compensation at a rate equal to a wholesale energy price.

In August 2015, SDG&E proposed a successor NEM tariff that is intended to ensure that all NEM customers pay for the grid and other services they receive, supports the continued growth and adoption of distributed energy resources and helps California meet its energy policy goals. In January 2016, SDG&E, Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (Edison) filed a joint recommendation to continue the pursuit of a fair and equitable rate structure for all customers. Subsequently in January 2016, the CPUC adopted a final decision in the case that makes modest changes now to require NEM customers to pay some costs that would otherwise be borne by non-NEM customers and moves new NEM customers to time-of-use rates. Together with a reduction in tiered rate differentials and the potential implementation of a fixed charge discussed under electric rate reform, the NEM successor tariff begins a process of reducing the cost burden on non-NEM customers. In March 2016, SDG&E, Edison, PG&E, TURN and the California Coalition of Utility Employees filed applications with the CPUC requesting rehearing of its January 2016 decision. In September 2016, the CPUC issued an order denying the rehearing requests in all respects. SDG&E implemented the adopted successor NEM tariff in July 2016, after reaching the 617-MW cap established for the prior NEM program.

Appropriate NEM reform is necessary to ensure that SDG&E is authorized to recover, from NEM customers, the costs incurred in providing grid and energy services, as well as mandated legislative and regulatory public policy programs. SDG&E believes this design would be preferable to recovering these costs from customers not participating in NEM. If NEM self-generating installations were to increase substantially between 2016 and 2019 when more significant reforms are to take effect, the rate structure adopted by the CPUC could have a material adverse effect on SDG&E’s business, cash flows, financial condition, results of operations and/or prospects. For additional discussion, see “Risk Factors” in the Annual Report.

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California Senate Bill 350

SB 350, signed into law in October 2015, creates new requirements for the utilities in the areas of renewable procurements, energy efficiency, resource planning, and electric vehicle (EV) infrastructure. Specifically, the state mandated renewable portfolio standard will be raised to 50 percent by 2030 and requires all load serving entities, including SDG&E, to file integrated resource plans that will ultimately enable the electric sector to achieve reductions in greenhouse gas emissions of 40 percent compared to 1990 levels by 2030. SB 350 also clearly specifies that the utilities will be asked to file applications with the CPUC that highlight how they can help with the development and expansion of the electric charging infrastructure necessary to support the growth of the EV market expected due to the state’s alternative fuel vehicle policy initiative. We expect to meet the higher renewable portfolio standard and greenhouse gas emissions reductions requirement and are supportive of greater infrastructure development to support electric vehicle charging. Our Electric Vehicle Charging Program, which we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, does not include potential additional opportunities associated with SB 350.

California Assembly Bill 2868

In September 2016, the Governor of the State of California signed AB 2868, which requires the CPUC to direct electrical corporations, including SDG&E, to file applications for programs and investments to accelerate the widespread deployment of distributed energy storage systems. AB 2868 sets a cap of 500 MW statewide, requires that no more than 25 percent of the capacity of distributed energy storage systems be on the customer side of the utility meter, and requires the CPUC to prioritize these programs and investments for the public sector and low-income customers.

SoCalGas Matters

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, located in Los Angeles County, which has been operated by SoCalGas since 1972. SoCalGas worked closely with several of the world’s leading experts to stop the leak, including planning and obtaining all necessary approvals for drilling relief wells. On February 18, 2016, the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR) confirmed that the well was permanently sealed.

Pursuant to a stipulation and court order, SoCalGas provided temporary relocation support to residents in the nearby community who requested it before the well was permanently sealed. In connection with the temporary relocation support, on April 27, 2016, the Los Angeles County Superior Court (Superior Court) issued an order extending the relocation support term pending the completion of the DPH’s indoor testing. Following the release of the results of the DPH’s indoor testing of certain homes in the Porter Ranch community, which concluded that indoor conditions did not present a long-term health risk and that it was safe for residents to return home, the Superior Court issued an order on May 20, 2016, as supplemented by the Superior Court on May 25, 2016, ruling that: (1) currently relocated residents be given the choice to request residence cleaning, to be performed according to the DPH’s proposed protocol and at SoCalGas’ expense, and (2) the relocation program for currently relocated residents would terminate. SoCalGas completed the cleaning program, and the relocation program ended July 24, 2016.

Various governmental agencies including the DOGGR, DPH, SCAQMD, Los Angeles Regional Water Quality Control Board (RWQCB), CARB, California Division of Occupational Safety and Health (DOSH), CPUC, Pipeline and Hazardous Materials Safety Administration (PHMSA), U.S. Environmental Protection Agency (EPA), Los Angeles County District Attorney’s Office, and California Attorney General’s Office, are investigating this incident. As discussed separately below, a federal joint interagency task force, co-chaired by the U.S. Department of Energy (DOE) and PHMSA, also is investigating the incident.

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by the Los Angeles County District Attorney discussed below, are coordinated before a single court in the Los Angeles County Superior Court for pretrial management. Pursuant to the parties’ agreement, the court ordered that the individual and business entity plaintiffs (other than a Proposition 65 case, the federal securities class action and the shareholder derivative cases) would proceed by filing consolidated master complaints. We provide further detail on these master complaints and the securities and derivative cases, as well as complaints filed by the California Attorney General, acting in her independent capacity, and on behalf of the people of the State of California and the CARB, together with the Los Angeles City Attorney; the SCAQMD; and the County of Los Angeles, on behalf of itself and the people of the State of California, in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

Separately, on February 2, 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. On February 16, 2016, SoCalGas pled not guilty to the complaint. On September 13, 2016, SoCalGas entered a plea of 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 $232,500, and up to $4 million in operational commitments, reimbursement and assessments in exchange for the District Attorney’s Office moving to dismiss the remaining counts at sentencing and settling the complaint. The sentencing hearing is currently scheduled for November 29, 2016, at which we expect the court to rule on the motion to dismiss and determine whether to enter judgment on the notice count pursuant to the plea agreement. On October 18, 2016, certain plaintiffs in the separate civil cases filed a “Victims’ Request for Withdrawal of Plea Agreement” with the court. We provide further detail regarding this proceeding in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

The costs of defending against these civil and criminal lawsuits and cooperating with these investigations, and any damages, restitution, and civil 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, could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

On January 6, 2016, the Governor of the State of California issued the Governor’s Order proclaiming a state of emergency to exist in Los Angeles County due to the natural gas leak at the Aliso Canyon facility. The Governor’s Order implements various orders with respect to:


▪	stopping the leak;


▪	protecting public health and safety;


▪	ensuring accountability; and


▪	strengthening oversight.

We provide further detail regarding the Governor’s Order and CARB’s Aliso Canyon Methane Leak Climate Impacts Mitigation Program, issued pursuant to the Governor’s Order, in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

On January 23, 2016, the Hearing Board of the SCAQMD ordered SoCalGas to, among other things, stop the leak, minimize the release of natural gas into the air, conduct air monitoring and fund SCAQMD community air monitoring and a public health study. We provide further detail regarding the SCAQMD Hearing Board’s order in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

On January 25, 2016, the DOGGR and CPUC selected Blade Energy Partners (Blade) to conduct an independent analysis under their supervision and to be funded by SoCalGas to investigate the technical root cause of the Aliso Canyon leak. We expect the root cause analysis to be completed in the first half of 2017, but the timing is under the control of Blade, the DOGGR and the CPUC. In addition, effective February 5, 2016, the DOGGR amended the California Code of Regulations to require all underground natural gas storage facility operators, including SoCalGas, to take further steps to help ensure the safety of their gas storage operations. On July 8, 2016, DOGGR issued a Discussion Draft of new permanent regulations for all storage fields in California.

On April 1, 2016, the DOE and PHMSA jointly announced the formation of an Interagency Task Force on Natural Gas Storage Safety in response to the leak at Aliso Canyon to assess and make recommendations on best practices, response plans and safe operation of gas storage facilities. On June 22, 2016, President Obama signed the “Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016” or the “PIPES Act of 2016.” In addition, each of the PHMSA, DOGGR, SCAQMD, EPA and CARB has commenced separate rulemaking proceedings to adopt further regulations covering natural gas storage facilities and injection wells. We provide further details regarding the PIPES Act, the report and recommendations issued on October 18, 2016 by the Interagency Task Force on Natural Gas Storage Safety, and regulations issued by DOGGR following the Governor’s Order, in Note 11 of the Notes to the Condensed Consolidated Financial Statements herein.

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grounds that no violations of the cited regulations occurred, the citations are all preempted by federal law, the citations were not issued in a timely manner, and two of the citations are duplicative.

The California legislature enacted and the Governor signed SB 380, which among other things: (1) continues the prohibition against SoCalGas injecting any natural gas into the Aliso Canyon natural gas storage facility until a comprehensive review of the safety of the gas storage wells at the facility is completed by governmental agencies; (2) requires the CPUC, in consultation with various governmental agencies and other entities, to determine the range of working gas necessary in Aliso Canyon to ensure safety and reliability for the region and just and reasonable rates in California, and publish a report with such determination for public review and comment; and (3) requires the CPUC, no later than July 1, 2017, to open a proceeding to determine the feasibility of minimizing or eliminating use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region.

The California legislature enacted and the Governor signed SB 887, which establishes a framework for revising State regulations over natural gas storage wells in California. Among other things, the statute directs: (1) CARB, in consultation with any local air district and DOGGR, to develop a natural gas storage facility monitoring program that includes continuous monitoring of the ambient concentration of natural gas to identify natural gas leaks and the presence of natural gas emissions in the atmosphere; (2) DOGGR, in consultation with CARB, to determine by regulation what constitutes a reportable leak from a gas storage well and the timeframe for reporting those leaks; (3) DOGGR to perform random onsite inspections of some gas storage wells annually and post the results on its website; (4) the operator of a gas storage well to develop and maintain a comprehensive gas storage well training and mentoring program for those employees whose job duties involve the safety of operations and maintenance of gas storage wells and associated equipment; and (5) the operator of a natural gas storage well to submit to DOGGR for review and approval a comprehensive set of data and information, including, among other things, data to demonstrate stored gas will be confined to an approved zone, a risk management plan and a natural gas leak prevention and response plan.

The California legislature enacted and the Governor signed SB 888, which requires that a penalty assessed against a gas corporation by the CPUC pursuant to the Public Utilities Act with regard to a natural gas storage facility leak must at least equal the amount necessary to fully offset the impact on the climate from the greenhouse gases emitted by the leak, as determined by CARB. The statute further requires the CPUC to consider the extent to which the gas corporation has mitigated or is in the process of mitigating the impact on the climate from greenhouse gas emissions resulting from the leak.

Additional hearings in the State Legislature, as well as with various other federal and state regulatory agencies, have been or are expected to be scheduled, additional legislation has been proposed in the State Legislature, and additional laws, orders, rules and regulations may be adopted. The Los Angeles County Board of Supervisors has formed a task force to review and potentially implement new, more stringent land use (zoning) requirements and associated regulations and enforcement protocols for oil and gas activities, including natural gas storage field operations. Such new requirements could materially affect new or modified uses of the Aliso Canyon and other natural gas storage fields located in the County, including review under the California Environmental Quality Act and mitigation of environmental impacts associated with new and modified uses of the fields.

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 could be significant and to the extent not covered by insurance or recoverable in customer rates, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

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. Aliso Canyon, with a storage capacity of 86 billion cubic feet (Bcf), is the largest SoCalGas storage facility and an important element of SoCalGas’ delivery system. Aliso Canyon represents 63 percent of SoCalGas’ owned natural gas storage inventory capacity. SoCalGas has not injected natural gas into Aliso Canyon since October 25, 2015, in accordance with the Governor’s Order, but in conflict with the CPUC’s reliability-based direction, which requires injections to reach higher inventory levels prior to the winter season. On March 4, 2016, the DOGGR issued Order 1109, Order to Take Specific Actions Regarding Aliso Canyon Gas Storage Facility (Safety Review Testing Regime). On April 7, 2016, SoCalGas announced its safety framework to comply with the DOGGR Order 1109, which consists of phased testing for each of the active injection wells in the Aliso Canyon storage facility. SoCalGas will continue this moratorium on further injections until all required approvals have been obtained.

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customer rates, and SoCalGas’ and Sempra Energy’s results of operations, cash flows and financial condition may be materially adversely affected.

In March 2016, the CPUC issued a decision directing 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 gas storage field. The CPUC will determine at a later time whether, and to what extent, the tracked revenues may be refunded to ratepayers. Pursuant to the CPUC’s decision, SoCalGas filed an advice letter requesting to establish a memorandum account to track all business-as-usual costs to own and operate the Aliso Canyon storage field, which has been protested by intervening parties. In July 2016, SoCalGas filed a supplemental advice letter that replaced the term “actual costs” with “normal, business-as-usual” before each reference to costs. In September 2016, the supplemental filing was approved and made effective as of March 17, 2016, the date of the decision directing the establishment of the account.

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 have been communicating with our insurance carriers and intend to pursue the full extent of our insurance coverage. These policies are subject to various policy limits, exclusions and conditions. There can be no assurance that we will be successful in obtaining insurance coverage for costs related to the leak under the applicable policies, and to the extent we are not successful, it could result in a material charge against the earnings of SoCalGas and Sempra Energy.

Our estimate as of September 30, 2016 of $763 million of certain costs in connection with the Aliso Canyon storage facility leak may rise significantly as more information becomes available, 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 Sempra Energy’s and SoCalGas’ cash flows, financial condition and results of operations. In addition, any costs not included in the $763 million estimate could be material, and to the extent not covered by insurance (including any costs in excess of applicable policy limits), could have a material adverse effect on Sempra Energy’s and SoCalGas’ cash flows, financial condition and results of operations.

We discuss this matter further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein and in “Risk Factors” in the Annual Report.

Industry Developments and Capital Projects

We describe capital projects, electric and natural gas regulation and rates, and other pending proceedings and investigations that affect the California Utilities in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

SEMPRA INTERNATIONAL

As we discuss in “Cash Flows from Investing Activities,” our investments will significantly impact our future performance. In addition to the discussion below, we provide information about these investments in “Capital Resources and Liquidity” herein and in our Annual Report.

Sempra South American Utilities

Overview

Sempra South American Utilities has historically provided relatively stable earnings and liquidity, and its future performance will depend primarily on the ratemaking and regulatory process, environmental regulations, foreign currency rate fluctuations and economic conditions. Sempra South American Utilities is also expected to provide earnings from construction projects when completed and from other investments, but will require substantial funding for these investments.

Revenues at Chilquinta Energía are based on rates set by the National Energy Commission (Comisión Nacional de Energía). The current rates for sub-transmission, in effect since 2011, and previously extended to cover 2015, have been further extended until December 2017. The next rate reviews for distribution are scheduled to be completed, with tariff adjustments also going into effect, in November 2016 and will cover the period from November 2016 to October 2020. The next rate reviews for sub-transmission are scheduled to be completed, with tariff adjustments also going into effect, in January 2018 and will cover the period from January 2018 to December 2019. A change in law issued in July 2016 will change the rate methodology for sub-transmission beginning in 2020.

Luz del Sur serves primarily regulated customers, and revenues are based on rates set by the Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería). The next rate reviews are scheduled to be completed in 2017 and will cover the period from November 2017 to October 2021.

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We discuss revenues at Sempra South American Utilities in Note 1 of the Notes to Consolidated Financial Statements in our Annual Report.

We discuss the impact of tax reform in Chile and Peru above in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” and in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report.

Sempra Energy has a combined $750 million in goodwill recorded at September 30, 2016 related to Chilquinta Energía and Luz del Sur. Goodwill is subject to impairment testing annually, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in our Annual Report.

Transmission Projects

Chilquinta Energía. Chilquinta Energía has 50-percent ownership in two joint ventures, Eletrans S.A. and Eletrans II S.A., with Sociedad Austral de Electricidad Sociedad Anónima (SAESA) to construct transmission lines in Chile.

In May 2012, Eletrans S.A. was awarded two 220-kilovolt (kV) transmission lines in Chile. The approximately 100-mile, $80 million transmission line extending from Cardones to Diego de Almagro was completed in November 2015. The remaining 50-mile, $85 million transmission line extending from Ciruelos to Pichirropulli is expected to be completed in the second half of 2017.

In June 2013, Eletrans II S.A. was awarded two 220-kV transmission lines in Chile. The transmission lines will extend approximately 60 miles, and we estimate the projects will cost approximately $80 million in total and be completed in 2018.

Once the transmission lines are in operation, they will earn a return in U.S. dollars, indexed to the Consumer Price Index, for twenty years and a regulated return thereafter.

Sempra South American Utilities has a U.S. dollar-denominated loan to Eletrans S.A., its affiliate, totaling $83 million outstanding at September 30, 2016 to provide project financing for the construction of transmission lines.

The projects will be financed by the joint venture partners during construction. Other financing may be pursued upon completion of the projects.

Luz del Sur. Luz del Sur has received regulatory approval for an amended transmission investment plan that includes the development and operation of four substations and their related transmission lines in Lima. We estimate that the project will cost approximately $150 million and be in service in 2016 and 2017 as portions are completed. In May 2016, Luz del Sur received regulatory approval for a second transmission investment plan that includes the development and operation of five substations and their related transmission lines in Lima. We estimate that the project will cost approximately $130 million and will be in service beginning in 2017 through 2020 as portions are completed. Once in operation, the capitalized cost of the projects will earn the regulated return for 30 years. The projects will be financed through Luz del Sur’s existing debt program in Peru’s capital markets.

Potential Pipeline Project

Sempra South American Utilities is in negotiations to purchase from Odebrecht, an unrelated third party, its 50-percent equity interest in an approximately $6.5 billion natural gas pipeline project currently under development in Southern Peru. The project is currently contracted under a 34-year, U.S. dollar denominated concession agreement to build, operate and maintain the pipeline with the government of Peru. Several significant issues still remain to be resolved before we would be in a position to enter into an agreement to purchase this 50-percent interest. There can be no assurance that these significant issues will be resolved or that we will be in a position to enter into an agreement to purchase this 50-percent interest.

Sempra Mexico

Overview

Sempra Mexico is expected to provide earnings from construction projects and from joint venture investments. We expect projects, joint venture investments and dividends in Mexico to be funded by available funds, including credit facilities, and funds internally generated by the Mexico businesses, securities issuances, project financing, interim funding from the parent, partnering in joint ventures and proceeds from the planned sale of its TdM natural gas-fired power plant.

On September 26, 2016, IEnova acquired from Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company) its 50-percent interest in Gasoductos de Chihuahua S. de R.L. de C.V. (GdC) for a purchase price of $1.144 billion (exclusive of $66 million of cash and cash equivalents acquired) plus the assumption of $364 million of long-term debt, increasing IEnova’s ownership interest in GdC to 100 percent. The assets involved in the acquisition include three natural gas pipelines, an ethane pipeline, and a liquid petroleum gas pipeline and associated storage terminal. The transaction excludes the Los Ramones Norte pipeline, which is owned under a separate joint venture with IEnova, PEMEX, BlackRock and First Reserve. IEnova will continue holding an indirect 25-percent ownership interest in the pipeline through GdC’s 50-interest interest in Ductos y Energéticos del Norte, S. de R.L. de C.V.

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(DEN). As of the acquisition date, IEnova accounts for its 50-percent interest in DEN as an equity method investment. PEMEX continues to hold its 50-percent interest in DEN. We expect the GdC acquisition to have strategic benefits, including opportunities for asset optimization and expansion into areas such as the transportation and storage of refined products, and a larger platform and presence in Mexico to participate in energy sector reform.

We paid $1.078 billion in cash ($1.144 billion less $66 million of cash and cash equivalents acquired), which was funded using interim financing provided by Sempra Global through a $1.150 billion bridge loan to IEnova. Sempra Global funded the transaction using commercial paper borrowings. On October 19, 2016, IEnova completed a private follow-on offering of its common stock in the U.S. and outside of Mexico and a concurrent public common stock offering in Mexico, which generated net proceeds of approximately $1.57 billion or 29.86 billion Mexican pesos (based on an exchange rate of 18.96 pesos to 1.00 U.S. dollar as of October 13, 2016). IEnova used a portion of the proceeds from the offerings to fully repay the Sempra Global bridge loan in October 2016. We discuss these offerings in Note 13 of the Notes to Condensed Consolidated Financial Statements herein.

IEnova recorded $1.375 billion in goodwill at September 30, 2016 related to its acquisition of GdC. Goodwill is subject to impairment testing annually, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in our Annual Report.

We discuss the acquisition further in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

In November 2015, a major U.S. credit rating agency revised PEMEX’s global foreign currency and local currency credit ratings from A3 to Baa1 and changed the outlook for its credit ratings to negative. In March 2016, the same major credit rating agency further downgraded PEMEX’s global foreign currency and local currency credit ratings from Baa1 to Baa3. In both May and October 2016, in connection with debt offerings by PEMEX, the same major credit agency reaffirmed that the outlook on PEMEX’s credit ratings remains negative. PEMEX is also subject to the control of the Mexican government, which could limit its ability to satisfy its external debt obligations. Although PEMEX is a State Productive Enterprise of Mexico, its financing obligations are not guaranteed by the Mexican government. As both a partner in the DEN joint venture and a customer with capacity contracts for transportation services on Sempra Mexico’s ethane and propane pipelines, if PEMEX were unable to meet any or all of its obligations to Sempra Mexico, it could have a material adverse effect on Sempra Energy’s financial condition, results of operations and cash flows.

On September 5, 2016, IEnova entered into an agreement to acquire 100 percent of the equity interests in the Ventika I and Ventika II (collectively, Ventika) wind power generation facilities for an estimated purchase price of $852 million, which includes the assumption of approximately $477 million of existing debt, subject to normal adjustments at closing. Ventika is a 252-MW wind farm located in Nuevo Leon, Mexico, which began commercial operations in April 2016. All of Ventika’s generation capacity is contracted under 20-year, U.S. dollar-denominated power purchase agreements with five private off-takers. We expect the acquisition to be completed in the fourth quarter of 2016, subject to the satisfaction of customary closing conditions, including receipt of approval from Mexico’s Comisión Federal de Competencia Económica (COFECE). The acquisition will be partially funded through debt financing at IEnova and a portion of the proceeds from the IEnova offerings discussed above.

In February 2016, management approved a plan to market and sell Sempra Mexico’s TdM, a 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As a result, we stopped depreciating the plant and classified the plant as held for sale. In connection with the sales process, in September 2016, Sempra Mexico obtained market information indicating that the fair value of TdM may be less than its carrying value. After performing an analysis of the information, Sempra Mexico reduced the carrying value of TdM by recognizing a noncash impairment charge of $131 million ($111 million after-tax) in the three months and nine months ended September 30, 2016 in Impairment Losses on Sempra Energy’s Condensed Consolidated Statements of Operations. We expect to complete the sale in the first half of 2017. We discuss TdM further in Notes 3 and 8 of the Notes to Condensed Consolidated Financial Statements herein.

Pipeline Projects

In October 2012, Sempra Mexico was awarded two contracts by the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE) to build and operate an approximately 500-mile pipeline network (Sonora pipeline) to transport natural gas from the U.S.-Mexico border south of Tucson, Arizona through the Mexican state of Sonora to the northern part of the Mexican state of Sinaloa along the Gulf of California. The network will be comprised of two segments that will interconnect to the U.S. interstate pipeline system. We estimate it will cost approximately $1 billion. The first segment was completed in stages, with a section completed in the fourth quarter of 2014 and the final section completed in August 2015. We expect to complete the second segment in the first half of 2017, though as discussed in Note 11 of the Condensed Consolidated Financial Statements herein, a dispute with the Bácum community of the Yaqui tribe could cause delays and add costs to this project. The capacity is fully contracted by the CFE under two 25-year contracts denominated in U.S. dollars.

In 2014, the GdC joint venture and affiliates of PEMEX executed agreements for the development of Los Ramones Norte, a natural gas pipeline of approximately 280 miles and two compression stations, which connects with the first phase of Los Ramones and runs to the vicinity of San Luis Potosi, with an estimated cost of $1.45 billion. The Los Ramones Norte pipeline was excluded from IEnova’s September 2016 acquisition of GdC, as we discuss above. Sempra Mexico retains an indirect 25-percent ownership interest

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in the pipeline through GdC’s interest in DEN. The pipeline began commercial operation in February 2016. The two compression stations began operations in June 2016. The pipeline’s capacity is fully contracted under a 25-year transportation services agreement with the National Center of Natural Gas Control (Centro Nacional de Control de Gas Natural, or CENAGAS), denominated in Mexican pesos, indexed to the U.S. dollar and adjusted annually for inflation and fluctuation of the exchange rate. The transportation services agreement was transferred from PEMEX to CENAGAS in January 2016.

Sempra Mexico has loans to DEN, its affiliate, totaling $89 million outstanding at September 30, 2016 to finance a portion of its investment in the Los Ramones Norte pipeline project.

In December 2014, Sempra Mexico entered into a natural gas transportation services agreement with CFE for a 25-year term, denominated in U.S. dollars, for 100 percent of the transport capacity of the Ojinaga pipeline, equal to 1.4 Bcf per day. Sempra Mexico will be responsible for the development, construction and operation of the approximately 137-mile, 42-inch pipeline, with an estimated cost of $300 million. We expect the pipeline to begin operations in the first half of 2017.

In July 2015, Sempra Mexico entered into a natural gas transportation services agreement with CFE for a 25-year term, denominated in U.S. dollars, for 100 percent of the transport capacity of the San Isidro pipeline, equal to 1.1 Bcf per day. Sempra Mexico will be responsible for the development, construction and operation of the approximately 14-mile pipeline, with an estimated cost of $110 million. We expect the pipeline to begin operations in the first half of 2017.

In May 2016, Sempra Mexico entered into a natural gas transportation services agreement with CFE for a 21-year term, denominated in U.S. dollars, for 100 percent of the transport capacity of the Empalme Lateral pipeline, equal to 226 million cubic feet (MMcf) per day. IEnova will be responsible for the development, construction and operation of the approximately 12-mile pipeline, with an estimated cost of $12 million. We expect the pipeline to begin operations in the first half of 2017.

In June 2016, Infraestructura Marina del Golfo, a joint venture between Sempra Mexico and a subsidiary of TransCanada Corporation (TransCanada), was awarded the right to build, own and operate the Sur de Texas – Tuxpan natural gas pipeline by the CFE. Sempra Mexico has a 40-percent interest in the joint venture and TransCanada owns the remaining 60-percent interest. The project has an estimated cost of $2.1 billion, is expected to be completed in late 2018 and is fully contracted under a 25-year natural gas transportation service contract, denominated in U.S. dollars, with the CFE.

Sempra Mexico continues to monitor CFE project opportunities and carefully analyze CFE bids in order to participate in those that fit its overall growth strategy. Competition for recent pipeline projects has been intense, with numerous bidders competing aggressively for these projects. There can be no assurance that IEnova will be successful in bidding for new CFE projects.

The ability to successfully complete pipeline projects, like other major construction projects, is subject to a number of risks and uncertainties. For a discussion of these risks and uncertainties, see “Risk Factors” in our Annual Report.

Renewables Projects

Rumorosa and Tepezalá II Solar Complexes. In September 2016, IEnova was awarded two solar energy projects in an auction conducted by Mexico’s National Center of Electricity Control (Centro Nacional de Control de Energía). The Rumorosa Solar complex is a 41-MW photovoltaic project located in Baja California, Mexico. The Tepezalá II Solar complex is a 100-MW photovoltaic project located in Aguascalientes, Mexico and will be developed in a partnership with Trina Solar. The projects have an estimated cost of $150 million, are expected to begin operations in the first half of 2019 and will be contracted by the CFE under a 15-year renewable energy and capacity agreement and a 20-year clean energy certificate agreement.

Energía Sierra Juárez. In June 2015, we began commercial operations of the first phase of the Energía Sierra Juárez wind generation project, a 50-percent joint venture with InterGen N.V. The project is designed to provide up to 1,200 MW of capacity if fully developed. The 155-MW first phase of the Energía Sierra Juárez wind generation project is fully contracted by SDG&E. Future expansion of Energía Sierra Juárez will depend, among other factors, on the ability to obtain additional power purchase contracts.

Sempra Mexico has a U.S. dollar-denominated loan of $14 million outstanding at September 30, 2016 to Energía Sierra Juárez, its affiliate, to finance the first phase of the project.

Energía Costa Azul LNG Terminal

In February 2015, Sempra Natural Gas, IEnova, and a subsidiary of PEMEX entered into a Memorandum of Understanding (MOU) to collaborate in exploring the development of a natural gas liquefaction project at IEnova’s existing regasification terminal at Energía Costa Azul. The MOU defines the basis for the parties to explore PEMEX’s participation in this potential liquefaction project, including joining efforts on its development and structuring agreements that would allow opportunities for PEMEX to become a customer, natural gas supplier and investor; we have also started to share development costs with PEMEX. Energía Costa Azul has profitable long-term regasification contracts for 100 percent of the facility, making the decision to pursue a new liquefaction facility dependent in part on whether the investment in a new liquefaction facility would, over the long term, be more beneficial than continuing to supply regasification services under our existing contracts. The MOU expires on February 13, 2017. Development of

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this project is subject to a number of 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, tolling capacity agreements and construction contracts; reaching a final investment decision; and other factors associated with this potential investment. See “Risk Factors” in our Annual Report.

SEMPRA U.S. GAS & POWER

Sempra Renewables

Overview

Sempra Renewables is developing and investing in renewable energy generation projects that have long-term contracts with electric load serving entities, which provide electric service to end-users and wholesale customers. The renewable energy projects have planned in-service dates through 2017. These projects require construction financing which may come from a variety of sources including 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 of these alternative financing sources impact the projects’ returns.

Sempra Renewables’ future performance and the demand for renewable energy is impacted by various market factors, most notably state mandated requirements to deliver a portion of total energy load from renewable energy sources. The rules governing these requirements are generally known as the Renewables Portfolio Standard (RPS). 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.

Sempra Renewables entered into, subject to certain conditions precedent, two tax equity arrangements to finance the cost of its Black Oak Getty Wind project and its Copper Mountain Solar 4, Mesquite Solar 2 and Mesquite Solar 3 projects, discussed below. In the third quarter of 2016, Sempra Renewables received a $78 million deposit in connection with its solar tax equity financing transaction and is expected to close both transactions in December 2016.

Apple Blossom Wind Project

In July 2016, Sempra Renewables acquired the Apple Blossom Wind project, a 100-MW wind farm currently under development in Huron County, Michigan. Consumers Energy has contracted for all of the energy generated from the project for 15 years upon project completion, which is expected by the end of 2017.

Black Oak Getty Wind Project

In March 2015, Sempra Renewables acquired the Black Oak Getty Wind project, a 78-MW wind farm currently under construction in Stearns County, Minnesota. Sempra Renewables is completing the construction of the wind farm, and we expect the project to be fully operational by the end of 2016. Minnesota Municipal Power Agency has contracted for the energy generated from the project for 20 years upon project completion.

Copper Mountain Solar

Copper Mountain Solar is a photovoltaic generation facility operated and under construction by Sempra Renewables in Boulder City, Nevada. When fully developed and constructed, the project will be capable of producing up to approximately 550 MW of solar power, with 458 MW currently in operation, of which Sempra Renewables has 50-percent ownership of 400 MW through joint venture partnerships, and 100-percent ownership of the 58-MW facility. It is being developed in multiple phases as power sales become contracted.

In July 2014, Sempra Renewables signed a 20-year power purchase agreement (PPA) with Edison for all of the solar power from Copper Mountain Solar 4 beginning in 2020. The CPUC approved the PPA in March 2015. We expect Copper Mountain Solar 4 to be in service by the end of 2016. Sempra U.S. Gas & Power will market the output from Copper Mountain Solar 4 before the start of the Edison contract term. Copper Mountain Solar 4 will total 94 MW when completed.

Mesquite Solar

Mesquite Solar is a photovoltaic generation facility under construction by Sempra Renewables in Maricopa County, Arizona. When fully developed and constructed, the project will be capable of producing up to approximately 500 MW of solar power, with 150 MW currently in operation in a joint venture with Consolidated Edison Development (Mesquite Solar 1). In June 2015, Sempra Renewables signed a 20-year power sale agreement with Edison for 100 MW of solar power from the second phase of Mesquite Solar (Mesquite Solar 2). The CPUC approved the PPA in December 2015. In July 2015, Sempra Renewables signed a 25-year PPA with the Western

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Area Power Administration on behalf of the U.S. Department of the Navy for 150 MW of solar power from the third phase of Mesquite Solar (Mesquite Solar 3). We expect Mesquite Solar 2 and 3 to be in service by the end of 2016.

Sempra Natural Gas

Natural Gas Storage

Our natural gas storage assets include operational and development assets at Bay Gas in Alabama and Mississippi Hub in Mississippi, as well as our development project, LA Storage, LLC (LA Storage) in Louisiana. LA Storage could be positioned to support LNG export from the Cameron LNG JV terminal (discussed in “Cameron Liquefaction” below) and other liquefaction projects, if anticipated cash flows support further investment. However, changes in the U.S. natural gas market could also lead to diminished natural gas storage values.

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. In addition, our LA Storage development project may be unable to attract cash flow commitments sufficient to support further investment or to extend its FERC construction permit beyond the current expiration date of June 2017. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage pipeline, that is not 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 recorded value. To the extent the recorded (carrying) value is in excess of the fair value, we would record a noncash impairment charge. The recorded value of our long-lived natural gas storage assets at September 30, 2016 is $1.5 billion. A significant impairment charge related to our gas storage assets would have a material adverse effect on our results of operations in the period in which it is recorded.

Sempra Natural Gas has 42 Bcf of operational working natural gas storage capacity (20 Bcf at Bay Gas and 22 Bcf at Mississippi Hub). Sempra Natural Gas’ natural gas storage facilities and projects include


▪	Bay Gas, a facility located 40 miles north of Mobile, Alabama, that provides underground storage and delivery of natural gas. Sempra Natural Gas owns 91 percent of the project. It is the easternmost salt dome storage facility on the Gulf Coast, with direct service to the Florida market and markets across the Southeast, Mid-Atlantic and Northeast regions.


▪	Mississippi Hub, located 45 miles southeast of Jackson, Mississippi, an underground salt dome natural gas storage project with access to shale basins of East Texas and Louisiana, traditional gulf supplies and LNG, with multiple interconnections to serve the Southeast and Northeast regions.


▪	LA Storage, a salt cavern development project in Cameron Parish, Louisiana. Sempra Natural Gas owns 77 percent of the project and ProLiance Transportation LLC owns the remaining 23 percent. The project’s location provides access to several LNG facilities in the area.

Cameron Liquefaction

Cameron LNG JV Three-Train Liquefaction Project. We discuss the 2014 formation of the Cameron LNG JV, including the contribution of our share of equity to the joint venture through the contribution of the Cameron LNG, LLC regasification terminal in Hackberry, Louisiana, in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report. The existing regasification terminal is capable of processing 1.5 Bcf of natural gas per day, and it currently generates revenue under a terminal services agreement for approximately 3.75 Bcf of natural gas storage and associated send-out rights of approximately 600 MMcf of natural gas per day through 2029. The agreement allows the customer to pay capacity reservation and usage fees to use the facilities to receive, store and regasify the customer’s LNG. As described below, we expect this agreement to be terminated when progress on the construction of the three-train liquefaction project makes regasification no longer possible under the terms of the regasification and storage agreement.

Construction on the current project began in the second half of 2014 under an engineering, procurement and construction (EPC) contract with a joint venture between 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. In late October 2016, Cameron LNG JV received indication from the EPC contractor that the in-service date for each train may be delayed. The contractor currently estimates updated in-service dates as follows: mid-2018 for train one, late 2018 for train two, and mid-2019 for train three. The joint venture and its partners are in the process of reviewing the schedule impacts and alternatives with the EPC contractor. Any such construction delays would likely defer a portion of the 2018 and 2019 earnings anticipated from this project.

The current liquefaction project under construction, which is utilizing Cameron LNG JV’s existing facilities, is comprised of three liquefaction trains designed to a nameplate capacity of 13.9 million tonnes per annum (Mtpa) of LNG with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. The anticipated incremental investment in the three-train liquefaction

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project is estimated to be approximately $7 billion, including the cost of the lump-sum, turnkey construction contract, development engineering costs and permitting costs, but excluding capitalized interest and other financing costs. The majority of the incremental investment will be project-financed and the balance provided by the project partners. 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. If construction, financing or other project costs are higher than we currently expect, we may have to contribute additional cash exceeding our current expectations. The total cost of the facility, including the cost of our original facility plus interest during construction, financing costs and required reserves, is estimated to be approximately $10 billion.

The joint venture has authorization to export LNG to both Free Trade Agreement (FTA) countries and to countries that do not have an FTA with the United States. Cameron LNG JV has 20-year liquefaction and regasification tolling capacity agreements in place with ENGIE S.A. (formerly GDF SUEZ S.A.) and affiliates of Mitsubishi Corporation and Mitsui & Co, Ltd., that subscribe the full nameplate capacity of the facility.

Sempra Natural Gas 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.

In August 2014, Sempra Energy and the project partners executed project financing documents for senior secured debt in an initial aggregate principal amount up to $7.4 billion for the purpose of financing the cost of development and construction of the Cameron LNG JV liquefaction project. Concurrently, Sempra Energy entered into completion guarantees under which it has severally guaranteed 50.2 percent of the debt, or a maximum principal amount of $3.7 billion. The project financing and completion guarantees became effective on October 1, 2014, and will terminate upon financial completion of the project, which will occur upon satisfaction of certain conditions, including all three trains achieving commercial operation and meeting certain operational performance tests. We expect the project to achieve financial completion and the completion guarantees to be terminated approximately nine months after all three trains achieve commercial operation.

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 problems, substantial construction delays and increased costs. As noted above, Cameron LNG JV has a turnkey EPC contract with a joint venture between CB&I Shaw Constructors, Inc. and Chiyoda International Corporation. If the contractor becomes unwilling or unable to perform according to the terms and timetable of the EPC contract, Cameron LNG JV could be required to engage a substitute contractor, which would result in project delays and increased costs, which could be significant. For a discussion 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 “Risk Factors” in the Annual Report.

Cameron LNG JV has a terminal services agreement with one customer that requires the customer to pay capacity reservation and usage fees to use its facilities to receive, store and regasify the customer’s LNG. There is a termination agreement in place that will result in the termination of this services agreement at the point during construction of the new liquefaction facilities when piping tie-ins to the existing regasification terminal become necessary.

In December 2014, Cameron LNG JV filed with the DOE for authorization to match the total export volumes allowed to be exported to FTA countries under the FERC permit. This would allow for increased export from the three-train facility of up to 2.95 Mtpa. In April 2015, Cameron LNG JV filed the corresponding DOE Non-FTA permit application.

Proposed Additional Cameron Liquefaction Expansion. Cameron LNG JV is also pursuing the permitting to expand the current configuration from the current three liquefaction trains under construction. The expansion project is expected to include 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). In February 2015, Cameron LNG JV filed the DOE FTA application and the pre-filing application at FERC for two additional trains and the one LNG storage tank. In May 2015, the joint venture filed a corresponding DOE Non-FTA permit application. In July 2015, Cameron LNG JV received approval of the DOE FTA application. In September 2015, Cameron LNG JV submitted the FERC application and was formally noticed by FERC in October 2015. In February 2016, Cameron LNG JV received the FERC environmental assessment and in May 2016, received the FERC permit. In July 2016, Cameron LNG JV received the authorization to export LNG to countries that do not have a free-trade agreement with the U.S.

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. One of the partners indicated to Sempra Energy and the other partners that it currently does not want to invest additional capital in Cameron LNG JV with respect to the expansion. As a result, discussions among the partners are taking place, and we are considering a variety of options to move this project forward. These activities have contributed to delays in developing firm pricing information and securing customer

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commitments. In light of these developments, we are unable to predict when we might receive the consents and approvals required to move forward on this project.

The expansion of the Cameron LNG JV facilities beyond the first three trains is subject to a number of risks and uncertainties, including obtaining customer commitments, completing the required commercial agreements, amending the Cameron LNG JV agreement among the partners, securing 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 “Risk Factors” in the Annual Report.

We discuss the deconsolidation of Cameron LNG, LLC, the Cameron LNG JV project financing obligations and Sempra Energy’s completion guarantee further in Notes 3 and 4 of the Notes to Consolidated Financial Statements in the Annual Report.

Other LNG Liquefaction Development

Design, regulatory and commercial activities are ongoing for potential LNG liquefaction developments at Sempra Mexico’s Energía Costa Azul facility and at our Port Arthur, Texas site. 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 2021 to 2025 time frame.

Port Arthur. In March 2015, Sempra Natural Gas submitted a request to the FERC to initiate the pre-filing review for 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 total export capability of approximately 10 Mtpa, or 1.4 Bcf per day; two 160,000-cubic-meter storage tanks; marine facilities for vessel berthing and loading; natural gas liquids and refrigerant storage; feed gas pre-treatment; truck loading and unloading areas; and combustion turbine generators for self-generation of electrical power.

In March 2015, Sempra Natural Gas also submitted a request to the FERC to initiate the pre-filing review for the proposed Port Arthur pipeline project. The proposed project consists of two 42-inch-diameter feed gas pipelines (7 and 27 miles long), two compressor stations, receipt meter stations, and other appurtenant facilities in Orange and Jefferson Counties, Texas, and Cameron Parish, Louisiana. The pipelines would provide up to 1.6 Bcf per day of capacity to the Port Arthur LNG facilities.

In March and June 2015, Sempra Natural Gas filed permit applications with the DOE for authorization to export the LNG produced from the proposed project to all current and future FTA and Non-FTA countries, respectively. In August 2015, Sempra Natural Gas received authorization from the DOE to export the LNG produced from the proposed project to all current and future FTA countries.

In February 2016, Sempra Natural Gas and Woodside Petroleum Ltd. (Woodside) entered into a project development agreement for the joint development of the proposed Port Arthur LNG liquefaction project. The agreement specifies how the parties will share costs, and establishes a framework for the parties to work jointly on permitting, design, engineering, commercial and marketing activities associated with developing the Port Arthur LNG liquefaction project.

Development of the Port Arthur LNG liquefaction project is subject to a number of risks and uncertainties, including completing the required commercial agreements, such as joint venture agreements, tolling capacity agreements or gas supply and LNG sales 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 “Risk Factors” in the Annual Report.

Energía Costa Azul. We further discuss Sempra Natural Gas’ participation in potential LNG liquefaction development at Sempra Mexico’s Energía Costa Azul facility above under “Sempra Mexico – Energía Costa Azul LNG Terminal.”

LNG Liquefaction Development Costs. Total expenditures on LNG liquefaction development for the nine months ended September 30, 2016 were $29 million, including capitalized costs of $15 million. After-tax LNG development costs expensed for the three months and nine months ended September 30, 2016 were $2 million and $8 million, respectively. We expect to expense approximately $10 million to $15 million, after-tax, in 2016 for liquefaction and LNG integrated midstream development costs.

RBS SEMPRA COMMODITIES

In three separate transactions in 2010 and one in early 2011, we and The Royal Bank of Scotland plc (RBS), our partner in the RBS Sempra Commodities joint venture, sold substantially all of the businesses and assets of our commodities-marketing partnership. The investment balance of $67 million at September 30, 2016 reflects remaining distributions expected to be received from the partnership as it is dissolved. The amount of distributions, if any, may be impacted by the matters we discuss related to RBS Sempra Commodities under “Other Litigation” in Note 11 of the Notes to Condensed Consolidated Financial Statements herein. In addition, amounts may be retained by the partnership for an extended period of time to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership.

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OTHER SEMPRA ENERGY MATTERS

We may be further impacted by depressed and rapidly changing economic conditions. These conditions may also affect our counterparties. Moreover, the dollar may fluctuate significantly compared to some foreign currencies, especially in Mexico and South America where we have significant operations. We discuss “Concentration of Credit Risk” in Note 11 of the Notes to Condensed Consolidated Financial Statements herein, “Impact of Foreign Currency and Inflation Rates on Results of Operations” and “Foreign Currency and Inflation Rate Risk” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein and “Credit Risk,” “Foreign Currency Rate Risk” and “Foreign Inflation Risk” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report. North American natural gas prices, when in decline, negatively affect profitability at Sempra Natural Gas. Also, a reduction in projected global demand for LNG could result in increased competition among those working on projects in an environment of declining LNG demand, such as the Sempra Energy-sponsored export initiatives. For a discussion of these risks and other risks involving changing commodity prices, see “Risk Factors” in the Annual Report.

In July 2010, federal legislation to reform financial markets was enacted that significantly alters how over-the-counter (OTC) derivatives are regulated, which may impact all of our businesses. The law increased regulatory oversight and transparency requirements of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the U.S. Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits, the latter of which is pending final approval. The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users. These requirements could cause our OTC transactions to be more costly and have a material adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products, they could limit the effectiveness and extent of our hedging programs, because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to mitigate and may be restricted on the size of our hedging program.

Our future performance depends substantially on the timing and success of our business development efforts and our construction, maintenance and capital projects. We discuss this and additional matters that could affect our future performance in Notes 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein, in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, and in “Risk Factors” in the Annual Report.

LITIGATION

We describe legal proceedings which could adversely affect our future performance in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

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.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We provide disclosure regarding derivative activity in Note 7 of the Notes to Condensed Consolidated Financial Statements herein. We discuss our market risk and risk policies in detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein and in the Annual Report.

INTEREST RATE RISK

The table below shows the nominal amount of long-term debt at September 30, 2016 and December 31, 2015:



NOMINAL AMOUNT OF LONG-TERM DEBT(1)
(Dollars in millions)
	September 30, 2016						December 31, 2015
	Sempra Energy Consolidated		SDG&E		SoCalGas		Sempra Energy Consolidated		SDG&E		SoCalGas
Utility fixed-rate	$	7,218	$	4,209	$	3,009	$	6,362	$	3,849	$	2,513
Utility variable-rate	447		447		—		455		455		—
Non-utility fixed-rate	5,968		—		—		6,780		—		—
Non-utility variable-rate	534		—		—		166		—		—


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

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 changed by ten percent on all of Sempra Energy’s effective variable-rate, long-term debt at September 30, 2016, the change in earnings over the next 12-month period ending September 30, 2017 would be $10 million (after-tax), including $8 million at SDG&E. These hypothetical changes in earnings are based on our long-term debt position after the effect of interest rate swaps.

We provide additional information about interest rate swap transactions in Note 7 of the Notes to Condensed Consolidated Financial Statements herein.

FOREIGN CURRENCY AND INFLATION RATE RISK

We discuss our foreign currency and inflation exposure above in “Results of Operations – Changes in Revenues, Costs and Earnings – Impact of Foreign Currency and Inflation Rates on Results of Operations” herein. We also discuss our foreign currency exposure at our Mexican and South American subsidiaries in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Foreign Currency Rate Risk” in the Annual Report.

The hypothetical effects for every 10 percent appreciation in the U.S. dollar against the currencies of Mexico, Chile and Peru in which we have operations and investments are as follows:



HYPOTHETICAL EFFECTS FROM 10 PERCENT STRENGTHENING OF U.S. DOLLAR
(Dollars in millions)
	Hypothetical effects
Translation of 2016 earnings to U.S. dollars(1)	$	(12	)
Transactional exposure, before the effects of foreign currency derivatives(2)	39
Transactional exposure, net of the effects of foreign currency derivatives(2)	1
Translation of net assets of foreign subsidiaries and investment in foreign entities(3)	(167		)


(1)	Amount represents the impact to earnings, primarily at our South American businesses, for a change in the average exchange rate throughout the reporting period.


(2)	Amount primarily represents the effects of currency exchange rate movement from September 30, 2016 on monetary assets and liabilities and translation of non-U.S. deferred income tax balances at our Mexican subsidiaries, which we discuss in "Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes" above.


(3)	Amount represents the effects of currency exchange rate movement from September 30, 2016 recorded to OCI at the end of each reporting period, primarily at our South American businesses.

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Monetary assets and liabilities at our Mexican subsidiaries that are denominated in U.S. dollars may fluctuate significantly throughout the year. These monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. Historically, Mexican inflation has remained below five percent. Based on a net monetary liability position of $1.9 billion, including those related to our investments in joint ventures, at September 30, 2016, the hypothetical effect of a five-percent increase in the Mexican inflation rate is approximately $19 million lower earnings as a result of higher income tax expense for our consolidated subsidiaries, as well as lower equity earnings for our joint ventures.

Impacts Related to GdC Acquisition

Due to the acquisition of PEMEX’s 50-percent interest in GdC by Sempra Mexico, which we discuss in Note 3 of the Notes to Consolidated Financial Statements, our exposure to foreign currency rate risk has increased and could have a material impact on our Mexican income tax expense. However, similar to our current Mexican operations, GdC’s functional currency is the U.S. dollar and its assets are covered by long-term, U.S. dollar-based contracts.

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 Securities and Exchange Commission and is accumulated and communicated to the management of each company, including each respective Chief Executive Officer and Chief 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 Chief Executive Officers and Chief Financial Officers of Sempra Energy, SDG&E and SoCalGas, each company evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of September 30, 2016, the end of the period covered by this report. Based on these evaluations, the Chief Executive Officers and Chief 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

Other than the changes which may be associated with the acquisition described below (which did not impact SDG&E or SoCalGas), 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.

On September 26, 2016, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein, we acquired PEMEX’s 50-percent interest in GdC. The net assets acquired, at fair value, were $2.3 billion, including goodwill, or 5 percent of total Sempra Energy assets at September 30, 2016. Losses from the date of acquisition through September 30, 2016, were $1 million, or less than 1 percent of total Sempra Energy earnings for the quarter ended September 30, 2016. We are in the process of integrating GdC. Our management is analyzing, evaluating and, where necessary, will implement changes in, GdC’s controls and procedures. Due to the limited period of time since the acquisition date, we have not had sufficient time to assess the internal controls of GdC for the quarter and year-to-date periods ended September 30, 2016. Therefore, we excluded GdC from our evaluation of internal control over financial reporting contained in this quarterly report and from our evaluation of disclosure controls and procedures above, to the extent subsumed by GdC’s internal control over financial reporting. We intend to include GdC in the overall assessment of, and report on, internal control over financial reporting as soon as practicable, but in no event later than one year from the date of acquisition.

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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 9, 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 13, 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, or 2) referred to in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein and in the Annual Report.

ITEM 1A. RISK FACTORS

There have not been any material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015.

ITEM 6. EXHIBITS

The following exhibits relate to each registrant as indicated.

EXHIBIT 3 -- BYLAWS AND ARTICLES OF INCORPORATION

San Diego Gas & Electric Company

3.1 Bylaws of San Diego Gas & Electric (as amended through October 26, 2016).

Southern California Gas Company

3.2 Bylaws of Southern California Gas Company (as amended through October 25, 2016) (SoCalGas Form 8-K filed on October 26, 2016, Exhibit 3.1).

EXHIBIT 10 -- MATERIAL CONTRACTS

Nuclear

Sempra Energy / San Diego Gas & Electric Company

10.1 Fourteenth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated February 18, 2016.

10.2 Fifteenth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated August 31, 2016.

10.3 Twelfth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated February 18, 2016.

10.4 Thirteenth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated August 31, 2016.

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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 Statement of Sempra Energy’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.2 Statement of Sempra Energy’s Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

San Diego Gas & Electric Company

31.3 Statement of San Diego Gas & Electric Company’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.4 Statement of San Diego Gas & Electric Company’s Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

Southern California Gas Company

31.5 Statement of Southern California Gas Company’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.6 Statement of Southern California Gas Company’s Chief 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 Statement of Sempra Energy’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.

32.2 Statement of Sempra Energy’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.

San Diego Gas & Electric Company

32.3 Statement of San Diego Gas & Electric Company’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.

32.4 Statement of San Diego Gas & Electric Company’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.

Southern California Gas Company

32.5 Statement of Southern California Gas Company’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.

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32.6 Statement of Southern California Gas Company’s Chief 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

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)

November 2, 2016	By: /s/ Trevor I. Mihalik
	Trevor I. Mihalik Senior 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)

November 2, 2016	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)

November 2, 2016	By: /s/ Bruce A. Folkmann
	Bruce A. Folkmann Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

139

Exhibit

Exhibit 3.1

SAN DIEGO GAS & ELECTRIC COMPANY

________________

BYLAWS

(As Amended Through October 26, 2016)

ARTICLE I

CORPORATE MANAGEMENT

The business and affairs of San Diego Gas & Electric Company (the “Corporation”) shall be managed, and all corporate powers shall be exercised, by or under the direction of the Board of Directors of the Corporation (the “Board”), subject to the Articles of Incorporation and the General Corporation Law of the State of California (the “General Corporation Law”).

ARTICLE II

OFFICERS

1. Designation. The officers of the Corporation (i) shall consist of a President, a Chief Financial Officer and a Secretary, and (ii) may consist of a Chairman of the Board (the “Chairman”), a Chief Executive Officer, a Chief Operating Officer, one or more Vice Presidents, one or more Assistant Secretaries, a Treasurer, one or more Assistant Treasurers, a Controller, one or more Assistant Controllers, and such other officers with such titles and duties as the Board may from time to time elect. Any two or more offices may be held by the same person.

2. Term. The officers of the Corporation shall be elected by the Board and serve at the pleasure of the Board and shall hold office until their resignation, removal or other disqualification from service, or until their successors are duly elected. Any officer may be removed from office at any time, with or without cause, by the vote of a majority of the authorized number of Directors. The Board may fill vacancies or elect new officers at any time.

3. Chairman. The Chairman shall be a Director and shall preside at meetings of the Board and meetings of the Shareholders, unless otherwise unavailable. The Chairman shall have such other duties and responsibilities as may be designated by the Board from time to time. Notwithstanding anything to the contrary contained herein, the Chairman need not be an officer of the Corporation.

4. Chief Executive Officer. The Chief Executive Officer of the Corporation shall be the general manager and chief executive officer of the Corporation, subject to the control of the Board, and as such shall direct the overall business, affairs and operations of the Corporation, shall have general supervision of the officers of the Corporation and shall have all such other authority as is incident to such office.

5. President. The duties of the President of the Corporation shall include, but not be limited to, assisting the Chief Executive Officer (to the extent the President is not also the Chief Executive Officer) in directing the overall business, affairs and operations of the Corporation. In the event that the Board has not appointed a Chief Executive Officer, the President of the Corporation shall be the general manager and chief executive officer of the Corporation, subject to the control of the Board, and as such shall direct the overall business, affairs and operations of the Corporation, and shall have general supervision of the officers of the Corporation and shall have all such other authority as is incident to such office.

6. Chief Operating Officer. The duties of the Chief Operating Officer of the Corporation shall include, but not be limited to, directing the day-to-day business, affairs and operations of the Corporation, under the supervision of the Chief Executive Officer and (to the extent neither the Chief Executive Officer nor the Chief Operating Officer is also the President) the President, and shall have all such other authority as is incident to such office.

7. Vice Presidents. The Vice Presidents, one of whom shall be the Chief Financial Officer, shall have such duties as the Chief Executive Officer or the Board shall designate and shall have all such other authority as is incident to such office.

8. Chief Financial Officer. The Chief Financial Officer shall be responsible for the overall management of the financial affairs of the Corporation, and shall have all such other authority as is incident to such office.

9. Secretary and Assistant Secretary. The Secretary shall attend all meetings of the Shareholders and the Board, keep a true and accurate record of the proceedings of all such meetings and attest the same by his or her signature, have charge of all books, documents and papers which appertain to the office, have custody of the corporate seal and affix it to all papers and documents requiring sealing, give all notices of meetings, and have and perform all other duties usually appertaining to the office and all duties designated by the Bylaws, the Chief Executive Officer or the Board. In the absence of the Secretary, any Assistant Secretary may perform the duties and shall have the powers of the Secretary.

10. Treasurer and Assistant Treasurer. The Treasurer shall perform all duties usually appertaining to the office and all duties designated by the Chief Executive Officer or the Board, and shall have all such other authority as is incident to such office. In the absence of the Treasurer, any Assistant Treasurer may perform the duties and shall have all the powers of the Treasurer.

11. Controller and Assistant Controller. The Controller shall be responsible for establishing financial control policies for the Corporation and shall perform all duties usually appertaining to the office and all duties designated by the Chief Executive Officer or the Board, and shall have all such other authority as is incident to such office. In the absence of the Controller, any Assistant Controller may perform the duties and shall have all the powers of the Controller.

12. Non-Officer Regional Vice Presidents. The non-officer Regional Vice Presidents shall have such powers and perform such duties as may be prescribed for them from time to time

by the Chairman, Chief Executive Officer, President, any Vice President or the Board. Non-Officer Vice Presidents shall not be formally elected by the Board and shall not be considered officers of the Corporation for purposes of Section 16 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or for purposes of California law. Such Non-Officer Vice Presidents shall not be deemed a Vice President of the Corporation as such term is described in Section 7 of Article II of these Bylaws.

ARTICLE III

DIRECTORS

1. Number. The Board shall consist of not less than four nor more than seven Directors. The exact authorized number of Directors shall be fixed from time to time, within the limits specified, by approval of the Board or the Shareholders.

2. Election. A Board shall be elected at each Annual Meeting of Shareholders and at any Special Meeting of Shareholders called for that purpose, including any adjournments thereof.

3. Vacancies. Vacancies in the Board may be filled as set forth in the Articles of Incorporation.

4. Compensation. Members of the Board shall receive such compensation and reimbursement of expenses as the Board may from time to time determine.

5. Regular Meetings. Regular meetings of the Board shall be held on such dates and at such times and places as may be designated by the Board. Notice of regular meetings of the Board need not otherwise be given to Directors.

6. Special Meetings. Special Meetings of the Board may be called at any time by the Chairman, the Chief Executive Officer, the President or one-third (but not less than two) of the Directors. Notice shall be given to each Director of the date, time and place of each Special Meeting of the Board. If given by mail, such notice shall be mailed to each Director at least four days before the date of such meeting. If given personally or by telephone (including a voice messaging system or other system or technology designed to record and communicate messages), telegraph, facsimile, electronic mail or other electronic means, such notice shall be given to each Director at least 24 hours before the time of such meeting. Notice of a meeting need not be given to any Director who signs a waiver of notice, whether before or after the meeting, or who attends the meeting without protesting, prior thereto or at its commencement, the lack of notice to such Director.

7. Quorum. One-third of the authorized number of Directors (but not less than two Directors) shall be necessary to constitute a quorum for the transaction of business. Except as otherwise provided by applicable law, the Articles of Incorporation or these Bylaws, every act or decision of a majority of the Directors present at a meeting at which a quorum is present shall be valid as the act of the Board, provided that a meeting at which a quorum is initially present may continue to transact business, notwithstanding the withdrawal of Directors, if any action taken is

approved by at least a majority of the required quorum for such meeting. A majority of Directors present at any meeting, whether or not a quorum is present, may adjourn the meeting to another time and place.

8. Action Upon Consent. Any action required or permitted to be taken by the Board may be taken without a meeting, if all members of the Board shall individually or collectively consent in writing to such action.

9. Tele-conference, Video Participation. Members of the Board may participate in a meeting through use of conference telephone or electronic video screen communication, so long as all members participating in the meeting can hear one another. Such participation constitutes presence in person at the meeting.

10. Directors Emeritus. The Board may from time to time elect one or more Directors Emeritus. Each Director Emeritus shall have the privilege of attending meetings of the Board, upon invitation of the Chairman, the Chief Executive Officer or the President. No Director Emeritus shall be entitled to vote on any business coming before the Board or be counted as a member of the Board for any purpose whatsoever.

ARTICLE IV

COMMITTEES

1.Committees. The Board may appoint one or more committees, each consisting of two or more Directors, to serve at the pleasure of the Board. The Board may delegate to such committees any or all of the authority of the Board except with respect to:

(a)The approval of any action which also requires the approval of the Shareholders or approval of the outstanding shares;

(b)The filling of vacancies on the Board or on any committee;

(c)The fixing of compensation of the Directors for serving on the Board or on any committee;

(d)The amendment or repeal of bylaws or the adoption of new bylaws;

(e)The amendment or repeal of any resolution of the Board which by its express terms is not so amendable or repealable;

(f)A distribution to the Shareholders, except at a rate, in a periodic amount or within a price range set forth in the Articles of Incorporation or determined by the Board; and

(g)The appointment of other committees of the Board or the members thereof.

Any such committee, or any member thereof, must be appointed by resolution adopted by a majority of the authorized number of Directors.

2.Notice of Meetings. Unless the Board shall establish different requirements for the giving of notice of committee meetings, notice of each meeting of any committee of the Board shall be given to each member of such committee, and the giving of such notice shall be subject to the same requirements as the giving of notice of Special Meetings of the Board, except that notice of regular meetings of any committee for which the date, time and place has been previously designated by resolution of the committee need not otherwise be given to members of the Committee.

3.Conduct of Meetings. The provisions of these Bylaws with respect to the conduct of meetings of the Board shall govern the conduct of committee meetings. Written minutes shall be kept of all committee meetings.

ARTICLE V

SHAREHOLDER MEETINGS

1.Annual Meeting.

(a)An Annual Meeting of Shareholders (the “Annual Meeting”) shall be held each year on such date and at such time as may be designated by resolution of the Board.

(b)At an Annual Meeting of Shareholders, only such business shall be conducted as shall have been properly brought before the Annual Meeting. To be properly brought before an Annual Meeting, business must be (i) specified in the notice of the Annual Meeting (or in any supplement or amendment thereto) given by or at the direction of the Board, (ii) brought before the Annual Meeting by or at the direction of the Board or by the Chairman, Chief Executive Officer or President, or (iii) otherwise brought before the Annual Meeting by a Shareholder who is entitled to vote at the Annual Meeting.

2.Special Meetings. Special meetings of the Shareholders (each, a “Special Meeting”) for any purpose whatsoever may be called at any time by the Chairman, the Chief Executive Officer, the President or the Board, or by one or more Shareholders holding not less than one-tenth of the voting power of the Corporation.

3.Place of Meetings. All meetings of the Shareholders shall be held at the principal office of the Corporation or at such other locations as may be designated by the Board.

4.Notice of Meetings. Written notice shall be given to each Shareholder entitled to vote of the date, time, place and general purpose of each meeting of Shareholders. Notice may be given personally, or by mail, or by telegram, or by electronic transmission as set forth in the California Corporations Code, charges prepaid, to the Shareholder’s physical or electronic address appearing on the books of the Corporation or given by the Shareholder to the Corporation for the purpose of notice. If a Shareholder supplies no address to the Corporation, notice shall be deemed to be given

if mailed to the place where the principal office of the Corporation is situated, or published at least once in some newspaper of general circulation in the county of said principal office. Notice of any meeting shall be sent to each Shareholder entitled thereto not less than 10 nor more than 60 days before such meeting.

5.Record Dates; Voting. The Board may fix a time in the future not less than 10 nor more than 60 days preceding the date of any meeting of Shareholders, or not more than 60 days preceding the date fixed for the payment of any dividend or distribution, or for the allotment of rights, or when any change or conversion or exchange of shares shall go into effect, as a record date for the determination of the Shareholders entitled to notice of and to vote at any such meeting or entitled to receive any such dividend or distribution, or any such allotment of rights, or to exercise the rights in respect to any such change, conversion, or exchange of shares. In such case, only Shareholders of record at the close of business on the date so fixed shall be entitled to notice of and to vote at such meeting or to receive such dividend, distribution or an allotment of rights, or to exercise such rights, as the case may be, notwithstanding any transfer of any shares on the books of the Corporation after any record date fixed as aforesaid, except as otherwise provided by the Articles of Incorporation or the General Corporation Law.

6.Quorum. At any Shareholders’ meeting a majority of the shares entitled to vote must be represented in order to constitute a quorum for the transaction of business, but a majority of the shares present, or represented by proxy, though less than a quorum, may adjourn the meeting to some other date, and from day to day or from time to time thereafter until a quorum is present.

ARTICLE VI

CERTIFICATES FOR SHARES

1.Form. Certificates for shares of the Corporation shall state the name of the registered holder of the shares represented thereby, and shall be signed by the Chairman, the President or a Vice President, and by the Chief Financial Officer, an Assistant Treasurer, the Secretary or an Assistant Secretary. Any such signature may be by facsimile thereof.

2.Surrender. Upon a surrender to the Secretary, or to a transfer agent or transfer clerk of the Corporation, of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment or authority to transfer, the Corporation shall issue a new certificate to the party entitled thereto, cancel the old certificate and record the transaction upon its books.

3.Right of Transfer. When a transfer of shares on the books is requested and there is a reasonable doubt as to the rights of the persons seeking such transfer, the Corporation, or its transfer agent or transfer clerk, before entering the transfer of the shares on its books or issuing any certificate therefor, may require from such person reasonable proof of his or her rights, and if there remains a reasonable doubt in respect thereto, may refuse a transfer unless such person shall give adequate security or a bond of indemnity executed by a corporate surety, or by two individual sureties, satisfactory to the Corporation as to form, amount and responsibility of sureties.

4.Conflicting Claims. The Corporation shall be entitled to treat the holder of record of any shares as the holder in fact thereof and shall not be bound to recognize any equitable or other claim to or interest in such shares on the part of any other person, whether or not it shall have express or other notice thereof, save as expressly provided by applicable law.

5.Loss, Theft and Destruction. In the case of the alleged loss, theft or destruction of any certificate for shares, another may be issued in its place as follows: (a) the owner of the lost, stolen or destroyed certificate shall file with the transfer agent of the Corporation a duly executed Affidavit of Loss and Indemnity Agreement and Certificate of Coverage, accompanied by a check representing the cost of the bond as outlined in any blanket lost securities and administration bond previously approved by the Directors of the Corporation and executed by a surety company satisfactory to them, which bond shall indemnify the Corporation, its transfer agents and registrars; or (b) the Board may, in its discretion, authorize the issuance of a new certificate to replace a lost, stolen or destroyed certificate on such other terms and conditions as it may determine to be reasonable.

ARTICLE VII

INDEMNIFICATION

1. Definitions. For the purposes of this Article, “agent of the Corporation” means any person (other than a Director or Officer of the Corporation) who (i) is or was an agent or employee of the Corporation, or (ii) is or was serving at the request of the Corporation as an agent or employee of another foreign or domestic corporation, partnership, joint venture, trust, or other enterprise, or (iii) was an agent or employee of a foreign or domestic corporation which was a predecessor corporation of the Corporation or of another enterprise at the request of such predecessor corporation or (iv) is or was an agent or employee of the Corporation or any of its subsidiaries and is or was serving at the request of the Corporation or any of its subsidiaries as a fiduciary or administrator of any employee benefit plan sponsored by the Corporation or any of its subsidiaries; “Director or Officer of the Corporation” means any person who (i) is or was a Director or officer of the Corporation, or (ii) is or was serving at the request of the Corporation as a Director or officer of another foreign or domestic corporation, partnership, joint venture, trust, or other enterprise, or (iii) is or was a Director or officer of the Corporation and is or was serving at the request of the Corporation as a Director, officer, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust, or other enterprise, or (iv) was a Director or officer of a foreign or domestic corporation which was a predecessor corporation of the Corporation or of another enterprise at the request of such predecessor corporation or (v) is or was a Director or officer of the Corporation or any of its subsidiaries and is or was serving at the request of the Corporation or any of its subsidiaries as a fiduciary or administrator of any employee benefit plan sponsored by the Corporation or any of its subsidiaries; “proceeding” means any threatened, pending or completed action or proceeding, whether civil, criminal, administrative, or investigative; and “expenses” includes, without limitation, attorneys’ fees and any expenses of establishing a right to indemnification under Sections 4 or 5(d) of this Article.

2. Indemnification for Third Party Actions. The Corporation shall indemnify any person who is or was a party, or is threatened to be made a party, to any proceeding (other than an action by or in the right of the Corporation to procure a judgment in its favor) by reason of the fact that such person is or was a Director or Officer of the Corporation against expenses, judgments, fines, settlements and other amounts actually and reasonably incurred in connection with such proceeding if such person acted in good faith and in a manner such person reasonably believed to be in the best interests of the Corporation, and, in the case of a criminal proceeding, had no reasonable cause to believe the conduct of such person was unlawful. The Corporation shall have, in its discretion, the power to indemnify any person who is or was a party, or is threatened to be made a party, to any proceeding (other than an action by or in the right of the Corporation to procure a judgment in its favor) by reason of the fact that such person is or was an agent of the Corporation against expenses, judgments, fines, settlements and other amounts actually and reasonably incurred in connection with such proceeding if such person acted in good faith and in a manner such person reasonably believed to be in the best interests of the Corporation, and, in the case of a criminal proceeding, had no reasonable cause to believe the conduct of such person was unlawful. The termination of any proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent shall not, of itself, create a presumption that the person did not act in good faith and in a manner which the person reasonably believed to be in the best interests of the Corporation or that the person had reasonable cause to believe that the person’s conduct was unlawful.

3. Indemnification for Derivative Actions. The Corporation shall indemnify any person who is or was a party or is threatened to be made a party to any threatened, pending or completed action by or in the right of the Corporation to procure a judgment in its favor by reason of the fact that such person is or was a Director or Officer of the Corporation, against expenses actually and reasonably incurred by such person in connection with the defense or settlement of such action, as well as, to the fullest extent permissible under California law and the Corporation’s Articles of Incorporation, judgments, fines, settlements and other amounts actually and reasonably incurred in connection with such action (whether or not any such item is deemed to be an expense) if such person acted in good faith and in a manner such person believed to be in the best interests of the Corporation and its Shareholders. The Corporation shall have, in its discretion, the power to indemnify any person who is or was a party or is threatened to be made a party to any threatened, pending or completed action by or in the right of the Corporation to procure a judgment in its favor by reason of the fact that such person is or was an agent of the Corporation, against expenses actually and reasonably incurred by such person in connection with the defense or settlement of such action, as well as, to the fullest extent permissible under California law and the Corporation’s Articles of Incorporation, judgments, fines, settlements and other amounts actually and reasonably incurred in connection with such action (whether or not any such item is deemed to be an expense) if such person acted in good faith and in a manner such person believed to be in the best interests of the Corporation and its Shareholders. No indemnification shall be made under this Section: (a) in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the Corporation in the performance of such person’s duty to the Corporation and its Shareholders, unless and only to the extent that the court in which such proceeding is or was pending shall determine upon application that, in view of all the circumstances of the case, such person is fairly and reasonably

entitled to indemnity for expenses and then only to the extent that the court shall determine; (b) of amounts paid in settling or otherwise disposing of a pending action without court approval; or (c) of expenses incurred in defending a pending action which is settled or otherwise disposed of without court approval.

4. Successful Defense. Notwithstanding any other provision of this Article, to the extent that a Director or Officer of the Corporation has been successful on the merits or otherwise (including the dismissal of an action without prejudice or the settlement of a proceeding or action without admission of liability) in defense of any proceeding referred to in Sections 2 or 3 of this Article, or in defense of any claim, issue or matter therein, the Director or Officer of the Corporation shall be indemnified against expenses (including attorneys’ fees) actually and reasonably incurred by the Director or Officer in connection therewith.

5. Indemnification Determination. Except as provided in Section 4, any indemnification under Section 3 of this Article shall be made by the Corporation only if authorized in the specific case, upon a determination that indemnification of the Director or Officer of the Corporation or agent of the Corporation is proper in the circumstances because the person has met the applicable standard of conduct set forth in Section 3, by (a) a majority vote of a quorum consisting of Directors who are not parties to such proceeding; (b) if such a quorum of Directors is not obtainable, by independent legal counsel in a written opinion; (c) approval by the affirmative vote of a majority of the shares of this Corporation represented and voting at a duly held meeting at which a quorum is present (which shares voting affirmatively also constitute at least a majority of the required quorum) or by the written consent of holders of a majority of the outstanding shares which would be entitled to vote at such meeting and, for such purpose, the shares owned by the person to be indemnified shall not be considered outstanding or entitled to vote; or (d) the court in which such proceeding is or was pending, upon application made by the Corporation, such Director or Officer or agent, or the attorney or other person rendering services in connection with the defense, whether or not such application by said Director or Officer or agent, attorney or other person is opposed by the Corporation.

6. Advancement of Expenses. Expenses incurred by a Director or Officer of the Corporation in defending any proceeding shall be advanced by the Corporation (and if otherwise authorized by the Board, expenses incurred by an agent of the Corporation in defending any proceeding may be advanced by the Corporation) prior to the final disposition of such proceeding upon receipt of an undertaking by or on behalf of the Director or Officer of the Corporation or agent of the Corporation to repay such amount if it shall be determined ultimately that such person is not entitled to be indemnified as authorized in this Article.

7. Restriction on Indemnification. No indemnification or advance shall be made under this Article, except as provided in Sections 4, 5(d) and 6 hereof, in any circumstance where it appears that it would be inconsistent with (a) a provision of the Articles of Incorporation of the Corporation, its bylaws, a resolution of the Shareholders or an agreement in effect at the time of the accrual of the alleged cause of action asserted in the proceeding in which the expenses were incurred or other

amounts were paid which prohibits or otherwise limits indemnification; or (b) any condition expressly imposed by a court in approving a settlement.

8. Non-Exclusive. The indemnification provided by this Article shall not be deemed exclusive of any other rights to which those seeking indemnification may be entitled under any statute, bylaw, agreement, vote of Shareholders or disinterested Directors or otherwise, both as to action in an official capacity and as to action in another capacity while holding such office. The rights to indemnification under this Article shall continue as to a person who has ceased to be a Director or Officer of the Corporation or agent of the Corporation and shall inure to the benefit of the heirs, executors and administrators of the person.

9. Expenses as a Witness. To the extent that any Director or Officer of the Corporation (or, to the extent authorized by the Board, any agent of the Corporation) is by reason of such position, or a position with another entity at the request of the Corporation, a witness in any action, suit or proceeding, he or she shall be indemnified against all costs and expenses actually and reasonably incurred by him or her or on his or her behalf in connection therewith.

10. Insurance. The Corporation may purchase and maintain directors and officers liability insurance and other liability insurance, at its expense, to protect itself and any Director or Officer of the Corporation or agent of the Corporation or another corporation, partnership, joint venture, trust or other enterprise against any expense, liability or loss asserted against or incurred by the person in such capacity or arising out of the Director’s or Officer’s or agent’s status as such, whether or not the Corporation would have the power to indemnify the Director, Officer or agent against such expense, liability or loss under the provisions of this Article or under the General Corporation Law.

11. Separability. Each and every paragraph, sentence, term and provision of this Article is separate and distinct so that if any paragraph, sentence, term or provision hereof shall be held to be invalid or unenforceable for any reason, such invalidity or unenforceability shall not affect the validity or enforceability of any other paragraph, sentence, term or provision hereof. To the extent required, any paragraph, sentence, term or provision of this Article may be modified by a court of competent jurisdiction to preserve its validity and to provide the claimant with, subject to the limitations set forth in this Article and any agreement between the Corporation and claimant, the broadest possible indemnification permitted under applicable law. If this Article or any portion hereof shall be invalidated on any ground by any court of competent jurisdiction, then the Corporation shall nevertheless have the power to indemnify each Director or Officer of the Corporation, or agent of the Corporation against expenses, judgments, fines, settlements and other amounts actually and reasonably incurred in connection with such action (whether or not any such item is deemed to be an expense) with respect to any action, suit, proceeding or investigation, whether civil, criminal or administrative, and whether internal or external, including a grand jury proceeding and including an action or suit brought by or in the right of the Corporation, to the fullest extent permissible by any applicable portion of this Article that shall not have been invalidated and to the fullest extent permissible under California law and the Corporation’s Articles of Incorporation.

12. Agreements. Upon, and in the event of, a determination of the Board to do so, the Corporation is authorized to enter into indemnification agreements with any or all of the Directors or Officers of the Corporation or agents of the Corporation providing for indemnification to the fullest extent permissible under California law and the Corporation’s Articles of Incorporation.

13. Retroactive Appeal. In the event this Article is repealed or modified so as to reduce the protection afforded herein, the indemnification provided by this Article shall remain in full force and effect with respect to any act or omission occurring prior to such repeal or modification. The rights of each Director or Officer of the Corporation to indemnification and advancement of expenses in this Article shall be deemed to be contractual rights.

ARTICLE VIII

OBLIGATIONS

All obligations of the Corporation, including promissory notes, checks, drafts, bills of exchange, and contracts of every kind, and evidences of indebtedness issued in the name of, or payable to, or executed on behalf of the Corporation, shall be signed or endorsed by such officer or officers, or agent or agents, of the Corporation and in such manner as, from time to time, shall be determined by the Board.

ARTICLE IX

CORPORATE SEAL

The corporate seal shall set forth the name of the Corporation and the state and date of incorporation.

ARTICLE X

AMENDMENTS

These Bylaws may be amended or repealed as set forth in the Articles of Incorporation.

ARTICLE XI

AVAILABILITY OF BYLAWS

A current copy of these Bylaws shall be mailed or otherwise furnished to any Shareholder of record within five days after receipt of a request therefor.

[Remainder of Page Intentionally Left Blank]

Exhibit

Exhibit 10.1

AMENDMENT NO. 14

TO THE

SAN DIEGO GAS & ELECTRIC COMPANY

NUCLEAR FACILITIES QUALIFIED CPUC DECOMMISSIONING

MASTER TRUST AGREEMENT

FOR

SAN ONOFRE NUCLEAR GENERATING STATIONS

This Amendment No. 14 made this 18th day of February, 2016, by and between San Diego Gas & Electric Company (“Company”) and The Bank of New York Mellon, a New York state bank, successor by operation of law to Mellon Bank, N.A (“Trustee”).

WHEREAS, pursuant to Section 2.12 of the Nuclear Facilities Qualified Decommissioning Master Trust for San Onofre Nuclear Generating Stations dated as of June 29, 1992, as amended (“Agreement”) between the Company and the Trustee, the parties specifically reserve the right to amend the Agreement;

NOW, THEREFORE, the Company and the Trustee agree as follows:


1.	Effective as of March 1, 2016, the Fee Schedule attached as Exhibit C to the Agreement shall be amended by deleting the fee description set forth under the title of “Manual activity charge” in its entirety and replacing it with the following:

“Manual Intervention* where automated solution exists (in addition to transaction fee) $100.00

*Manual Intervention is defined as transactions not being transmitted to BNY Mellon electronically via standard SWIFT/ISO formatted messages (including instructions that require repair) following SMPG and ISITC best practices, or, via Workbench, our secure, on-line transaction and reporting system.”


2.	Each Party hereby represents and warrants to the others that it has full authority to enter into this Amendment No. 14 upon the terms and conditions hereof and that the individual executing this Amendment No. 14 on its behalf has the requisite authority to bind that Party.

IN WITNESS WHEREOF, the Company, the Trustee, and the California Public Utilities Commission have set their hands and seals in agreement to these amendments as of the latest date set forth below.

SAN DIEGO GAS & ELECTRIC COMPANY


By:	________________________________________


Date:	________________________________________


Attest:	________________________________________

THE BANK OF NEW YORK MELLON


By:	________________________________________


Date:	________________________________________


Attest:	________________________________________

CALIFORNIA PUBLIC UTILITIES COMMISSION


By:	________________________________________


Date:	________________________________________


Attest:	________________________________________

Exhibit

Exhibit 10.2

AMENDMENT NO. 15

TO THE

SAN DIEGO GAS & ELECTRIC COMPANY

NUCLEAR FACILITIES QUALIFIED CPUC DECOMMISSIONING

MASTER TRUST AGREEMENT

FOR

SAN ONOFRE NUCLEAR GENERATING STATIONS

This Amendment No. 15 made this 31st day of August, 2016, by and between San Diego Gas & Electric Company (“Company”) and The Bank of New York Mellon, a New York state bank, successor by operation of law to Mellon Bank, N.A (“Trustee”).

WHEREAS, pursuant to Section 2.12 of the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Stations dated as of June 29, 1992, as amended (“Agreement”) between the Company and the Trustee, the parties specifically reserve the right to amend the Agreement;

NOW, THEREFORE, the Company and the Trustee agree as follows:


1.	The following sentence shall be added to Section 1.05:

“The tax partnership maintained under this Agreement shall be known as the SDG&E Qualified Nuclear Decommissioning Trust Partnership”.


2.	Each Party hereby represents and warrants to the others that it has full authority to enter into this Amendment No. 15 upon the terms and conditions hereof and that the individual executing this Amendment No. 15 on its behalf has the requisite authority to bind that Party.

IN WITNESS WHEREOF, the Company, the Trustee, and the California Public Utilities Commission have set their hands and seals in agreement to these amendments as of the latest date set forth below.

SAN DIEGO GAS & ELECTRIC COMPANY


By:	________________________________________


Date:	________________________________________


Attest:	________________________________________

THE BANK OF NEW YORK MELLON


By:	________________________________________


Date:	________________________________________


Attest:	________________________________________

CALIFORNIA PUBLIC UTILITIES COMMISSION


By:	________________________________________


Date:	________________________________________


Attest:	________________________________________

Exhibit

Exhibit 10.3

AMENDMENT NO. 12

TO THE

SAN DIEGO GAS & ELECTRIC COMPANY

NUCLEAR FACILITIES NON-QUALIFIED CPUC DECOMMISSIONING

MASTER TRUST AGREEMENT

FOR

SAN ONOFRE NUCLEAR GENERATING STATIONS

This Amendment No. 12 made this 18th day of February, 2016, by and between San Diego Gas & Electric Company (“Company”) and The Bank of New York Mellon, a New York state bank, successor by operation of law to Mellon Bank, N.A (“Trustee”).

WHEREAS, pursuant to Section 2.10 of the Nuclear Facilities Non-Qualified Decommissioning Master Trust for San Onofre Nuclear Generating Stations dated as of June 29, 1992, as amended (the “Agreement”) between the Company and the Trustee, the parties specifically reserve the right to amend the Agreement;

NOW, THEREFORE, the Company and the Trustee agree as follows:


1.	Effective as of March 1, 2016, the Fee Schedule attached as Exhibit C to the Agreement shall be amended by deleting the fee description set forth under the title of “Manual activity charge” in its entirety and replacing it with the following:

“Manual Intervention* where automated solution exists (in addition to transaction fee) $100.00


2.	Each Party hereby represents and warrants to the others that it has full authority to enter into this Amendment No. 12 upon the terms and conditions hereof and that the individual executing this Amendment No. 12 on its behalf has the requisite authority to bind that Party.

IN WITNESS WHEREOF, the Company, the Trustee, and the California Public Utilities Commission have set their hands and seals in agreement to these amendments as of the latest date set forth below.

SAN DIEGO GAS & ELECTRIC COMPANY


By:	________________________________________


Date:	________________________________________


Attest:	________________________________________

THE BANK OF NEW YORK MELLON


By:	________________________________________


Date:	________________________________________


Attest:	________________________________________

CALIFORNIA PUBLIC UTILITIES COMMISSION


By:	________________________________________


Date:	________________________________________


Attest:	________________________________________

Exhibit 10.3

Exhibit

Exhibit 10.4

AMENDMENT NO. 13

TO THE

SAN DIEGO GAS & ELECTRIC COMPANY

NUCLEAR FACILITIES NON-QUALIFIED CPUC DECOMMISSIONING

MASTER TRUST AGREEMENT

FOR SAN ONOFRE

NUCLEAR GENERATING STATIONS

This Amendment No. 13 made this 31st day of August, 2016, by and between San Diego Gas & Electric Company (“Company”) and The Bank of New York Mellon, a New York state bank, successor by operation of law to Mellon Bank, N.A (“Trustee”).

WHEREAS, pursuant to Section 2.10 of the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Stations dated as of June 29, 1992, as amended (the “Agreement”) between the Company and the Trustee, the parties specifically reserve the right to amend the Agreement;

NOW, THEREFORE, the Company and the Trustee agree as follows:


1.	The following sentence shall be added to Section 1.05:

“This Agreement has also been known as, the SDG&E Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust for San Onofre Nuclear Generating Stations.”


2.	Each Party hereby represents and warrants to the others that it has full authority to enter into this Amendment No. 13 upon the terms and conditions hereof and that the individual executing this Amendment No. 13 on its behalf has the requisite authority to bind that Party.

IN WITNESS WHEREOF, the Company, the Trustee, and the California Public Utilities Commission have set their hands and seals in agreement to these amendments as of the latest date set forth below.

SAN DIEGO GAS & ELECTRIC COMPANY


By:	________________________________________


Date:	________________________________________


Attest:	________________________________________

THE BANK OF NEW YORK MELLON


By:	________________________________________


Date:	________________________________________


Attest:	________________________________________

CALIFORNIA PUBLIC UTILITIES COMMISSION


By:	________________________________________


Date:	________________________________________


Attest:	________________________________________

Exhibit



		EXHIBIT 12.1
		SEMPRA ENERGY
		COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
		AND PREFERRED STOCK DIVIDENDS
		(Dollars in millions)




			2011		2012		2013		2014		2015		September 30, 2016
Fixed charges and preferred stock dividends:
Interest			$	549	$	601	$	620	$	636	$	677	$	528
Interest portion of annual rentals			2		2		2		3		2		2
Preferred dividends of subsidiaries(1)			10		6		6		1		2		1
Total fixed charges			561		609		628		640		681		531
Preferred dividends for purpose of ratio			—		—		—		—		—		—
Combined fixed charges and preferred dividends for purpose of ratio			$	561	$	609	$	628	$	640	$	681	$	531
Earnings:
Pretax income from continuing operations before
adjustment for income or loss from equity investees			$	1,747	$	1,255	$	1,399	$	1,443	$	1,600	$	1,321
Add:
Total fixed charges (from above)			561		609		628		640		681		531
Distributed income of equity investees			96		50		51		61		83		52
Less:
Interest capitalized			27		53		23		40		69		64
Preferred dividends of subsidiaries(1)			10		6		6		1		2		1
Total earnings for purpose of ratio			$	2,367	$	1,855	$	2,049	$	2,103	$	2,293	$	1,839
Ratio of earnings to combined fixed charges
and preferred stock dividends			4.22		3.05		3.26		3.29		3.37		3.46

Ratio of earnings to fixed charges			4.22		3.05		3.26		3.29		3.37		3.46

(1	)	In computing this ratio, “Preferred dividends of subsidiaries” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

Exhibit



	EXHIBIT 12.2
	SAN DIEGO GAS & ELECTRIC COMPANY
	COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
	AND PREFERRED STOCK DIVIDENDS
	(Dollars in millions)




		2011		2012		2013		2014		2015		September 30, 2016
Fixed charges and preferred stock dividends:
Interest		$	193	$	220	$	231	$	238	$	241	$	178
Interest portion of annual rentals		1		1		1		1		1		1
Total fixed charges		194		221		232		239		242		179
Preferred stock dividends(1)		7		7		5		—		—		—
Combined fixed charges and preferred stock dividends for purpose of ratio		$	201	$	228	$	237	$	239	$	242	$	179
Earnings:
Pretax income from continuing operations		$	692	$	705	$	626	$	797	$	890	$	622
Add: Total fixed charges (from above)		194		221		232		239		242		179
Less: Interest capitalized		1		—		—		1		—		—
Total earnings for purpose of ratio		$	885	$	926	$	858	$	1,035	$	1,132	$	801
Ratio of earnings to combined fixed charges
and preferred stock dividends		4.40		4.06		3.62		4.33		4.68		4.47

Ratio of earnings to fixed charges		4.56		4.19		3.70		4.33		4.68		4.47

(1)	In computing this ratio, “Preferred stock dividends” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

Exhibit



	EXHIBIT 12.3
	SOUTHERN CALIFORNIA GAS COMPANY
	COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
	AND PREFERRED STOCK DIVIDENDS
	(Dollars in millions)




		2011		2012		2013		2014		2015		September 30, 2016
Fixed charges and preferred stock dividends:
Interest		$	77	$	77	$	76	$	77	$	96	$	82
Interest portion of annual rentals		1		1		1		2		1		1
Total fixed charges		78		78		77		79		97		83
Preferred stock dividends(1)		2		2		2		2		2		1
Combined fixed charges and preferred stock dividends for purpose of ratio		$	80	$	80	$	79	$	81	$	99	$	84
Earnings:
Pretax income from continuing operations		$	431	$	369	$	481	$	472	$	558	$	274
Add: Total fixed charges (from above)		78		78		77		79		97		83
Less: Interest capitalized		1		1		1		1		1		1
Total earnings for purpose of ratio		$	508	$	446	$	557	$	550	$	654	$	356
Ratio of earnings to combined fixed charges
and preferred stock dividends		6.35		5.58		7.05		6.79		6.61		4.24

Ratio of earnings to fixed charges		6.51		5.72		7.23		6.96		6.74		4.29

(1)	In computing this ratio, “Preferred stock dividends” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

Exhibit

EXHIBIT 31.1

CERTIFICATION

I, Debra L. Reed, certify that:


1.	I have reviewed this report on Form 10-Q of Sempra Energy;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



November 2, 2016	/s/ Debra L. Reed
	Debra L. Reed
	Chief Executive Officer

Exhibit

EXHIBIT 31.2

CERTIFICATION

I, Joseph A. Householder, certify that:


1.	I have reviewed this report on Form 10-Q of Sempra Energy;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



November 2, 2016	/s/ Joseph A. Householder
	Joseph A. Householder
	Chief Financial Officer

Exhibit

EXHIBIT 31.3

CERTIFICATION

I, J. Walker Martin, certify that:


1.	I have reviewed this report on Form 10-Q of San Diego Gas & Electric Company;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



November 2, 2016	/s/ J. Walker Martin
	J. Walker Martin
	Chief Executive Officer

Exhibit

EXHIBIT 31.4

CERTIFICATION

I, Bruce A. Folkmann, certify that:


1.	I have reviewed this report on Form 10-Q of San Diego Gas & Electric Company;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



November 2, 2016	/s/ Bruce A. Folkmann
	Bruce A. Folkmann
	Chief Financial Officer

Exhibit

EXHIBIT 31.5

CERTIFICATION

I, Dennis V. Arriola, certify that:


1.	I have reviewed this report on Form 10-Q of Southern California Gas Company;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



November 2, 2016	/s/ Dennis V. Arriola
	Dennis V. Arriola
	Chief Executive Officer

Exhibit

EXHIBIT 31.6

CERTIFICATION

I, Bruce A. Folkmann, certify that:


1.	I have reviewed this report on Form 10-Q of Southern California Gas Company;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and


d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



November 2, 2016	/s/ Bruce A. Folkmann
	Bruce A. Folkmann
	Chief Financial Officer

Exhibit

Exhibit 32.1

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Sempra Energy (the "Company") certifies that:


(i)	the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2016 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


(ii)	the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



November 2, 2016	/s/ Debra L. Reed
	Debra L. Reed
	Chief Executive Officer

Exhibit

Exhibit 32.2

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Sempra Energy (the "Company") certifies that:


(i)	the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2016 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


(ii)	the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



November 2, 2016	/s/ Joseph A. Householder
	Joseph A. Householder
	Chief Financial Officer

Exhibit

Exhibit 32.3

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of San Diego Gas & Electric Company (the "Company") certifies that:


(i)	the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2016 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


(ii)	the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



November 2, 2016	/s/ J. Walker Martin
	J. Walker Martin
	Chief Executive Officer

Exhibit

Exhibit 32.4

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of San Diego Gas & Electric Company (the "Company") certifies that:


(i)	the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2016 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


(ii)	the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



November 2, 2016	/s/ Bruce A. Folkmann
	Bruce A. Folkmann
	Chief Financial Officer

Exhibit

Exhibit 32.5

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Southern California Gas Company (the "Company") certifies that:


(i)	the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2016 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


(ii)	the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



November 2, 2016	/s/ Dennis V. Arriola
	Dennis V. Arriola
	Chief Executive Officer

Exhibit

Exhibit 32.6

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Southern California Gas Company (the "Company") certifies that:


(i)	the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2016 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


(ii)	the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



November 2, 2016	/s/ Bruce A. Folkmann
	Bruce A. Folkmann
	Chief Financial Officer