Southern California Gas Company PFD 6% (SOCGM) 10-Q 2016 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C.  20549
FORM 10-Q
(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended		March 31, 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 8th 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 April 28, 2016:
Sempra Energy		249,496,738 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	74
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	109
Item 4.	Controls and Procedures	110
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	111
Item 1A.	Risk Factors	111
Item 6.	Exhibits	111
Signatures		113

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, Mexican Competition Commission, cities and counties, and other regulatory, governmental and environmental bodies in the United States and other 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 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 regulatory agency authorization to recover costs in rates from customers;

§   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; 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;

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

§   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; terrorist attacks that threaten system operations and critical infrastructure; and wars;

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

§   weather conditions, natural disasters, catastrophic accidents, equipment failures and other events that may disrupt our operations, damage our facilities and systems, cause the release of greenhouse gasses, 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 or may be disputed by insurers;

§   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 of 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 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 March 31,
	2016		2015
	(unaudited)
REVENUES
Utilities	$	2,442	$	2,422
Energy-related businesses		180		260
Total revenues		2,622		2,682
EXPENSES AND OTHER INCOME
Utilities:
Cost of natural gas		(311)		(346)
Cost of electric fuel and purchased power		(515)		(481)
Energy-related businesses:
Cost of natural gas, electric fuel and purchased power		(56)		(98)
Other cost of sales		(35)		(35)
Operation and maintenance		(701)		(658)
Depreciation and amortization		(328)		(303)
Franchise fees and other taxes		(111)		(107)
Plant closure adjustment		―		21
Equity (losses) earnings, before income tax		(22)		19
Other income, net		49		39
Interest income		6		7
Interest expense		(143)		(134)
Income before income taxes and equity earnings
of certain unconsolidated subsidiaries		455		606
Income tax expense		(142)		(163)
Equity earnings, net of income tax		17		15
Net income		330		458
Earnings attributable to noncontrolling interests		(11)		(21)
Earnings	$	319	$	437
Basic earnings per common share	$	1.28	$	1.76
Weighted-average number of shares outstanding, basic (thousands)		249,734		247,722
Diluted earnings per common share	$	1.27	$	1.74
Weighted-average number of shares outstanding, diluted (thousands)		251,412		251,206
Dividends declared per share of common stock	$	0.76	$	0.70
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Three months ended March 31, 2016 and 2015
	(unaudited)
	Sempra Energy shareholders' equity
	Pretax		Income tax		Net-of-tax		Noncontrolling
	amount		(expense) benefit		amount		interests (after-tax)		Total
2016:
Net income	$	461	$	(142)	$	319	$	11	$	330
Other comprehensive income (loss):
Foreign currency translation adjustments		68		―		68		5		73
Financial instruments		(159)		75		(84)		(5)		(89)
Pension and other postretirement benefits		2		(1)		1		―		1
Total other comprehensive loss		(89)		74		(15)		―		(15)
Comprehensive income	$	372	$	(68)	$	304	$	11	$	315
2015:
Net income	$	600	$	(163)	$	437	$	21	$	458
Other comprehensive income (loss):
Foreign currency translation adjustments		(62)		―		(62)		(8)		(70)
Financial instruments		(89)		34		(55)		(5)		(60)
Pension and other postretirement benefits		2		(1)		1		―		1
Total other comprehensive loss		(149)		33		(116)		(13)		(129)
Comprehensive income	$	451	$	(130)	$	321	$	8	$	329
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		March 31,		December 31,
		2016		2015(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	376	$	403
Restricted cash			23		27
Accounts receivable – trade, net			1,100		1,283
Accounts receivable – other			177		190
Due from unconsolidated affiliates			7		6
Income taxes receivable			49		30
Inventories			231		298
Regulatory balancing accounts – undercollected			256		307
Fixed-price contracts and other derivatives			88		80
Assets held for sale, power plant			303		―
Other			273		267
Total current assets			2,883		2,891
Other assets:
Restricted cash			20		20
Due from unconsolidated affiliates			186		186
Regulatory assets			3,336		3,273
Nuclear decommissioning trusts			1,082		1,063
Investments			2,727		2,905
Goodwill			849		819
Other intangible assets			402		404
Dedicated assets in support of certain benefit plans			432		464
Insurance receivable for Aliso Canyon costs			660		325
Sundry			825		761
Total other assets			10,519		10,220
Property, plant and equipment:
Property, plant and equipment			38,541		38,200
Less accumulated depreciation and amortization			(10,108)		(10,161)
Property, plant and equipment, net ($376 and $383 at March 31, 2016 and             December 31, 2015, respectively, related to VIE)			28,433		28,039
Total assets		$	41,835	$	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)
		March 31,		December 31,
		2016		2015(1)
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt		$	1,177	$	622
Accounts payable – trade			1,028		1,133
Accounts payable – other			129		142
Due to unconsolidated affiliates			13		14
Dividends and interest payable			360		303
Accrued compensation and benefits			259		423
Regulatory balancing accounts – overcollected			45		34
Current portion of long-term debt			1,066		907
Fixed-price contracts and other derivatives			57		56
Customer deposits			147		153
Reserve for Aliso Canyon costs			302		274
Other			549		551
Total current liabilities			5,132		4,612
Long-term debt ($300 and $303 at March 31, 2016 and December 31, 2015, respectively,      related to VIE)			12,975		13,134
Deferred credits and other liabilities:
Customer advances for construction			148		149
Pension and other postretirement benefit plan obligations, net of plan assets			1,165		1,152
Deferred income taxes			3,222		3,157
Deferred investment tax credits			32		32
Regulatory liabilities arising from removal obligations			2,850		2,793
Asset retirement obligations			2,151		2,126
Fixed-price contracts and other derivatives			248		240
Deferred credits and other			1,188		1,176
Total deferred credits and other liabilities			11,004		10,825
Commitments and contingencies (Note 11)
Equity:
Preferred stock (50 million shares authorized; none issued)			―		―
Common stock (750 million shares authorized; 249 million and 248 million shares
outstanding at March 31, 2016 and December 31, 2015, respectively; no par value)			2,642		2,621
Retained earnings			10,125		9,994
Accumulated other comprehensive income (loss)			(821)		(806)
Total Sempra Energy shareholders’ equity			11,946		11,809
Preferred stock of subsidiary			20		20
Other noncontrolling interests			758		750
Total equity			12,724		12,579
Total liabilities and equity		$	41,835	$	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)
	Three months ended March 31,
	2016		2015
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	330	$	458
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		328		303
Deferred income taxes and investment tax credits		112		131
Plant closure adjustment		―		(21)
Equity losses (earnings)		5		(34)
Fixed-price contracts and other derivatives		4		11
Other		2		(27)
Net change in other working capital components		165		19
Insurance receivable for Aliso Canyon costs		(335)		―
Changes in other assets		(29)		(42)
Changes in other liabilities		10		13
Net cash provided by operating activities		592		811
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(971)		(780)
Expenditures for investments and acquisition of business		(30)		(34)
Distributions from investments		9		1
Purchases of nuclear decommissioning and other trust assets		(94)		(95)
Proceeds from sales by nuclear decommissioning and other trusts		93		94
Increases in restricted cash		(16)		(18)
Decreases in restricted cash		20		25
Advances to unconsolidated affiliates		(6)		(5)
Repayments of advances to unconsolidated affiliates		9		33
Other		(3)		9
Net cash used in investing activities		(989)		(770)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(161)		(149)
Issuances of common stock		15		17
Repurchases of common stock		(54)		(65)
Issuances of debt (maturities greater than 90 days)		55		938
Payments on debt (maturities greater than 90 days)		(54)		(654)
Increase (decrease) in short-term debt, net		531		(363)
Tax benefit related to share-based compensation		34		52
Other		(2)		(7)
Net cash provided by (used in) financing activities		364		(231)
Effect of exchange rate changes on cash and cash equivalents		6		(3)
Decrease in cash and cash equivalents		(27)		(193)
Cash and cash equivalents, January 1		403		570
Cash and cash equivalents, March 31	$	376	$	377
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
	Three months ended March 31,
	2016		2015
	(unaudited)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	97	$	83
Income tax payments, net of refunds		41		42
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Acquisition of business:
Assets acquired	$	―	$	10
Liabilities assumed		―		(2)
Accrued purchase price		―		(6)
Cash paid	$	―	$	2
Accrued capital expenditures	$	423	$	272
Financing of build-to-suit property		―		27
Common dividends issued in stock		13		13
Dividends declared but not paid		197		181
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended March 31,
	2016		2015
	(unaudited)
Operating revenues
Electric	$	843	$	805
Natural gas		148		161
Total operating revenues		991		966
Operating expenses
Cost of electric fuel and purchased power		248		228
Cost of natural gas		39		54
Operation and maintenance		246		217
Depreciation and amortization		159		145
Franchise fees and other taxes		63		61
Plant closure adjustment		―		(21)
Total operating expenses		755		684
Operating income		236		282
Other income, net		14		9
Interest expense		(48)		(52)
Income before income taxes		202		239
Income tax expense		(72)		(88)
Net income		130		151
Earnings attributable to noncontrolling interest		(1)		(4)
Earnings attributable to common shares	$	129	$	147
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Three months ended March 31, 2016 and 2015
	(unaudited)
	SDG&E shareholder's equity
	Pretax		Income tax		Net-of-tax		Noncontrolling
	amount		expense		amount		interest (after-tax)		Total
2016:
Net income	$	201	$	(72)	$	129	$	1	$	130
Other comprehensive income (loss):
Financial instruments		―		―		―		(2)		(2)
Total other comprehensive loss		―		―		―		(2)		(2)
Comprehensive income (loss)	$	201	$	(72)	$	129	$	(1)	$	128
2015:
Net income	$	235	$	(88)	$	147	$	4	$	151
Other comprehensive income (loss):
Financial instruments		―		―		―		(2)		(2)
Total other comprehensive loss		―		―		―		(2)		(2)
Comprehensive income	$	235	$	(88)	$	147	$	2	$	149
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		March 31,		December 31,
		2016		2015(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	36	$	20
Restricted cash			21		23
Accounts receivable – trade, net			300		331
Accounts receivable – other			18		17
Due from unconsolidated affiliates			1		1
Inventories			72		75
Regulatory balancing accounts – net undercollected			256		307
Regulatory assets			119		107
Fixed-price contracts and other derivatives			50		53
Other			64		70
Total current assets			937		1,004
Other assets:
Restricted cash			2		―
Deferred taxes recoverable in rates			921		914
Other regulatory assets			968		977
Nuclear decommissioning trusts			1,082		1,063
Sundry			331		301
Total other assets			3,304		3,255
Property, plant and equipment:
Property, plant and equipment			16,668		16,458
Less accumulated depreciation and amortization			(4,284)		(4,202)
Property, plant and equipment, net ($376 and $383 at March 31, 2016 and             December 31, 2015, respectively, related to VIE)			12,384		12,256
Total assets		$	16,625	$	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)
		March 31,		December 31,
		2016		2015(1)
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt		$	166	$	168
Accounts payable			295		377
Due to unconsolidated affiliates			49		55
Income taxes payable			59		―
Interest payable			39		39
Accrued compensation and benefits			67		129
Accrued franchise fees			46		66
Current portion of long-term debt			191		50
Asset retirement obligations			63		99
Fixed-price contracts and other derivatives			53		51
Customer deposits			71		72
Other			130		101
Total current liabilities			1,229		1,207
Long-term debt ($300 and $303 at March 31, 2016 and December 31, 2015,     respectively, related to VIE)			4,294		4,455
Deferred credits and other liabilities:
Customer advances for construction			44		46
Pension and other postretirement benefit plan obligations, net of plan assets			216		212
Deferred income taxes			2,497		2,472
Deferred investment tax credits			20		19
Regulatory liabilities arising from removal obligations			1,692		1,629
Asset retirement obligations			745		729
Fixed-price contracts and other derivatives			107		106
Deferred credits and other			378		364
Total deferred credits and other liabilities			5,699		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			4,022		3,893
Accumulated other comprehensive income (loss)			(8)		(8)
Total SDG&E shareholder's equity			5,352		5,223
Noncontrolling interest			51		53
Total equity			5,403		5,276
Total liabilities and equity		$	16,625	$	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)
	Three months ended March 31,
	2016		2015
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	130	$	151
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		159		145
Deferred income taxes and investment tax credits		20		56
Plant closure adjustment		―		(21)
Fixed-price contracts and other derivatives		(1)		(1)
Other		(9)		(1)
Net change in other working capital components		103		7
Changes in other assets		(34)		(48)
Changes in other liabilities		1		11
Net cash provided by operating activities		369		299
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(329)		(355)
Purchases of nuclear decommissioning trust assets		(93)		(94)
Proceeds from sales by nuclear decommissioning trusts		93		94
Increases in restricted cash		(10)		(10)
Decreases in restricted cash		10		10
Increase in loans to affiliates, net		―		(66)
Other		(1)		―
Net cash used in investing activities		(330)		(421)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuances of debt (maturities greater than 90 days)		―		388
Payments on debt (maturities greater than 90 days)		(20)		(3)
Decrease in short-term debt, net		(2)		(246)
Capital distributions made by Otay Mesa VIE		(1)		(2)
Net cash (used in) provided by financing activities		(23)		137
Increase in cash and cash equivalents		16		15
Cash and cash equivalents, January 1		20		8
Cash and cash equivalents, March 31	$	36	$	23
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	46	$	39
Income tax (refunds) payments, net		(8)		31
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY
Accrued capital expenditures	$	104	$	103
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended March 31,
	2016		2015
	(unaudited)
Operating revenues	$	1,033	$	1,048
Operating expenses
Cost of natural gas		253		267
Operation and maintenance		327		314
Depreciation and amortization		122		113
Franchise fees and other taxes		37		34
Total operating expenses		739		728
Operating income		294		320
Other income, net		10		8
Interest expense		(22)		(19)
Income before income taxes		282		309
Income tax expense		(87)		(95)
Net income/Earnings attributable to common shares	$	195	$	214
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Three months ended March 31, 2016 and 2015
	(unaudited)
	Pretax		Income tax		Net-of-tax
	amount		expense		amount
2016:
Net income/Comprehensive income	$	282	$	(87)	$	195
2015:
Net income/Comprehensive income	$	309	$	(95)	$	214
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		March 31,		December 31,
		2016		2015(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	14	$	58
Accounts receivable – trade, net			445		635
Accounts receivable – other			99		99
Due from unconsolidated affiliates			8		48
Inventories			33		79
Regulatory assets			8		7
Other			44		40
Total current assets			651		966
Other assets:
Regulatory assets arising from pension obligations			715		699
Other regulatory assets			686		636
Insurance receivable for Aliso Canyon costs			660		325
Sundry			252		207
Total other assets			2,313		1,867
Property, plant and equipment:
Property, plant and equipment			14,359		14,171
Less accumulated depreciation and amortization			(4,896)		(4,900)
Property, plant and equipment, net			9,463		9,271
Total assets		$	12,427	$	12,104
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
		March 31,		December 31,
		2016		2015(1)
		(unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term debt		$	5	$	―
Accounts payable – trade			351		422
Accounts payable – other			77		76
Due to unconsolidated affiliate			34		―
Income taxes payable			27		3
Accrued compensation and benefits			110		160
Regulatory balancing accounts – net overcollected			45		34
Current portion of long-term debt			9		9
Customer deposits			70		76
Reserve for Aliso Canyon costs			302		274
Other			193		184
Total current liabilities			1,223		1,238
Long-term debt			2,481		2,481
Deferred credits and other liabilities:
Customer advances for construction			104		103
Pension obligation, net of plan assets			733		716
Deferred income taxes			1,643		1,532
Deferred investment tax credits			13		14
Regulatory liabilities arising from removal obligations			1,139		1,145
Asset retirement obligations			1,367		1,354
Deferred credits and other			380		372
Total deferred credits and other liabilities			5,379		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			2,475		2,280
Accumulated other comprehensive income (loss)			(19)		(19)
Total shareholders’ equity			3,344		3,149
Total liabilities and shareholders’ equity		$	12,427	$	12,104
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Three months ended March 31,
	2016		2015
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	195	$	214
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		122		113
Deferred income taxes and investment tax credits		59		(9)
Other		(7)		(6)
Net change in other working capital components		243		85
Insurance receivable for Aliso Canyon costs		(335)		―
Changes in other assets		(37)		(19)
Changes in other liabilities		1		(3)
Net cash provided by operating activities		241		375
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(340)		(315)
Decrease (increase) in loans to affiliate, net		50		(74)
Net cash used in investing activities		(290)		(389)
CASH FLOWS FROM FINANCING ACTIVITY
Increase (decrease) in short-term debt, net		5		(50)
Net cash provided by (used in) financing activity		5		(50)
Decrease in cash and cash equivalents		(44)		(64)
Cash and cash equivalents, January 1		58		85
Cash and cash equivalents, March 31	$	14	$	21
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	17	$	17
Income tax payments (refunds), net		3		(3)
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY
Accrued capital expenditures	$	148	$	129
See Notes to Condensed Consolidated 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. 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’ Condensed Consolidated Financial Statements include its accounts and the de minimis accounts of inactive subsidiaries. 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.

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 March 31, 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 Natural Gas owns Mobile Gas Service Corporation (Mobile Gas) in southwest Alabama and Willmut Gas Company (Willmut Gas) in Mississippi, and Sempra Mexico owns Ecogas México, S. de R.L. de C.V. (Ecogas) in northern Mexico, all natural gas distribution utilities. The California Utilities, Mobile Gas, Willmut Gas, 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.

Pipeline projects currently under construction by IEnova that are both regulated by the Comisión Reguladora de Energía (or CRE, the Energy Regulatory Commission) and 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, “Revenue from Contracts with Customers: Deferral of the Effective Date,” ASU 2016-08, “Revenue from Contracts with Customers: Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” and ASU 2016-10, “Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing”: ASU 2014-09 provides accounting guidance for 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 and 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.

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

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 value 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 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 are currently evaluating the full effect of the standard on our ongoing financial reporting, and have not yet concluded as to whether we will elect an early adoption. If we early adopt in 2016, we will recognize a $34 million tax benefit in earnings, which is currently recorded in Shareholders’ Equity, related to the three months ended March 31, 2016, and a benefit to retained earnings as of January 1, 2016 of approximately $107 million, both associated with the provision in ASU 2016-09 to recognize all excess tax benefits related to share-based compensation.

NOTE 3. ACQUISITION AND DIVESTITURE ACTIVITY

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

ACQUISITION

Sempra Renewables

In March 2015, Sempra Renewables invested $8 million to acquire a 100-percent interest in the Black Oak Getty Wind project, a 78-megawatt (MW) wind farm under development 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 in late 2016.

POTENTIAL ACQUISITION

Sempra Mexico

IEnova and Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company) are 50-50 partners in the joint venture Gasoductos de Chihuahua (GdC). GdC develops and operates energy infrastructure in Mexico. On July 31, 2015, IEnova entered into an agreement to purchase PEMEX’s 50-percent interest for $1.325 billion (excluding the assumption of approximately $170 million of net debt), which upon closing would increase its interest from 50 percent to 100 percent. The assets involved in the acquisition included three natural gas pipelines, an ethane pipeline, and a liquid petroleum gas pipeline and associated storage terminal. The transaction excluded the Los Ramones Norte pipeline that is owned under a separate joint venture with GdC, PEMEX, BlackRock and First Reserve, keeping IEnova’s interest in the pipeline at the current 25 percent.

In December 2015, Mexico’s Comisión Federal de Competencia Económica (COFECE or Mexican Competition Commission) objected to the transaction based upon previous antitrust rulings on PEMEX’s indirect ownership of two of the assets, the TDF S. de R.L. de C.V. liquid petroleum gas pipeline and the San Fernando natural gas pipeline, included in the acquisition as proposed. COFECE specified that these assets must be offered by PEMEX in a competitive bidding process as a prerequisite for approval of any transaction involving these two assets. COFECE’s decision did not object to IEnova’s acquisition of the assets on a market concentration basis. The parties are in the process of restructuring the transaction so that PEMEX can proceed with a bidding process on these two assets in accordance with the COFECE ruling. IEnova will have the right to approve the winning bidder as a new partner. Any restructured transaction will require negotiation of satisfactory terms for the revised transaction, and will also be subject to IEnova and PEMEX board approvals and satisfactory completion of the Mexican antitrust review, and may require further approvals from Mexican authorities.

ASSETS HELD FOR SALE, POWER PLANT

Sempra Mexico

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 twelve 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, and we stop recording depreciation expense on the asset.

In February 2016, management approved a plan to market and sell Sempra Mexico’s Termoeléctrica de Mexicali, 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 classifying Termoeléctrica de Mexicali as held for sale, we recognized $29 million in Income Tax Expense on Sempra Energy’s Condensed Consolidated Statement of Operations in the three months ended March 31, 2016 for a deferred Mexican income tax liability related to the excess of carrying value over the tax basis (outside basis difference). This outside basis difference resulted from undistributed earnings and movements in foreign exchange rates and inflation. The deferred tax liability on the outside basis difference was not previously recognized due to exceptions provided in U.S. GAAP, which no longer apply as a result of classifying the plant as held for sale. As this $29 million ($24 million after noncontrolling interest) of Mexican income tax expense on our outside basis difference is based on current carrying value, foreign exchange rates and inflation at March 31, 2016, this amount could change in future periods until the date of sale.

At March 31, 2016, the carrying amounts of the major classes of assets and related liabilities held for sale associated with the plant are as follows:

ASSETS HELD FOR SALE, POWER PLANT
(Dollars in millions)
		March 31, 2016
Cash and cash equivalents		$	1
Inventories			8
Other current assets			29
Other assets			15
Property, plant and equipment, net			250
Total assets held for sale		$	303
Accounts payable		$	1
Other current liabilities			7
Deferred income taxes			16
Asset retirement obligations			4
Other liabilities			15
Total liabilities held for sale(1)		$	43
(1)	Included in Other Current Liabilities on the Sempra Energy Condensed Consolidated Balance Sheet.

We considered the estimated fair value of the plant, less costs to sell, and determined that no adjustment to carrying value was required. In estimating fair value, we used both a market approach and discounted cash flow valuation techniques. In the event that the estimated sales price, less transaction costs, is less than the carrying value, or updated market information indicates fair value may be less than carrying value, we would recognize a loss in our results of operations at that time. We expect to complete the sale in the second half of 2016.

PENDING DIVESTITURE

Sempra Natural Gas

On March 29, 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 approximately $440 million, subject to adjustment at closing. The transaction is subject to customary closing conditions. Sempra Natural Gas expects the transaction to close in the second quarter of 2016.

At the date of the agreement, the carrying value of Sempra Natural Gas’ investment in Rockies Express was $484 million. 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 (Losses) Earnings, Before Income Tax, on the Sempra Energy Condensed Consolidated Statement of Operations for the three months ended March 31, 2016. We discuss non-recurring fair value measures and the associated accounting impact on our investment in Rockies Express in Note 8.

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

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

SEMPRA RENEWABLES

Sempra Renewables invested cash of $15 million and $17 million in its joint ventures during the three months ended March 31, 2016 and 2015, respectively.

SEMPRA NATURAL GAS

Sempra Natural Gas capitalized $12 million of interest during both the three months ended March 31, 2016 and 2015 and invested cash of $3 million during the three months ended March 31, 2015 at Cameron LNG Holdings, LLC (Cameron LNG JV).

In March 2016, Sempra Natural Gas entered into an agreement to sell its 25-percent interest in Rockies Express, which we discuss in Note 3.

GUARANTEES

We discuss guarantees that we have provided, which have a maximum aggregate amount of $4.5 billion, in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report. These guarantees have an aggregate carrying value of $67 million at March 31, 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
		March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015
SDG&E		$	3	$	6	$	―	$	―	$	69	$	69	$	72	$	75
SoCalGas(1)			―		49		―		―		33		30		33		79
Sempra South American Utilities			―		―		―		―		37		30		37		30
Sempra Mexico			―		―		6		3		2		10		8		13
Sempra Renewables			―		―		―		―		3		3		3		3
Sempra Natural Gas			74		94		3		3		1		1		78		98
Sempra Energy Consolidated		$	77	$	149	$	9	$	6	$	145	$	143	$	231	$	298
(1)	At both March 31, 2016 and December 31, 2015, SoCalGas' natural gas inventory for core customers is net of the estimated inventory loss related to the Aliso Canyon natural gas leak, which we discuss in Note 11.

GOODWILL

We discuss goodwill in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. The increase in goodwill from $819 million at December 31, 2015 to $849 million at March 31, 2016 is due to foreign currency translation at Sempra South American Utilities. We record the offset of this fluctuation in Other Comprehensive Income (Loss).

VARIABLE INTEREST ENTITIES

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

§   the purpose and design of the VIE;

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

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

§   the obligation to absorb losses or 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 $51 million at March 31, 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 $312 million at March 31, 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 March 31,
	2016		2015
Operating expenses
Cost of electric fuel and purchased power	$	(17)	$	(18)
Operation and maintenance		4		4
Depreciation and amortization		7		6
Total operating expenses		(6)		(8)
Operating income		6		8
Interest expense		(5)		(4)
Income before income taxes/Net income		1		4
Earnings attributable to noncontrolling interest		(1)		(4)
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 at March 31, 2016. In addition to the tolling agreements described above, other variable interests involve various elements of fuel and power costs, including certain construction costs, tax credits, 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 considered to be a VIE generally 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), was $872 million at March 31, 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 upon 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 March 31,
	2016		2015		2016		2015
Service cost	$	28	$	30	$	5	$	7
Interest cost		40		39		11		12
Expected return on assets		(42)		(44)		(17)		(17)
Amortization of:
Prior service cost (credit)		3		3		―		(1)
Actuarial loss		6		8		―		―
Regulatory adjustment		(28)		(29)		2		―
Total net periodic benefit cost	$	7	$	7	$	1	$	1

NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
	Pension benefits				Other postretirement benefits
	Three months ended March 31,
	2016		2015		2016		2015
Service cost	$	7	$	8	$	1	$	2
Interest cost		10		10		2		2
Expected return on assets		(12)		(14)		(3)		(3)
Amortization of:
Prior service cost		―		―		1		1
Actuarial loss		3		2		―		―
Regulatory adjustment		(7)		(5)		(1)		(2)
Total net periodic benefit cost	$	1	$	1	$	―	$	―

NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
	Pension benefits				Other postretirement benefits
	Three months ended March 31,
	2016		2015		2016		2015
Service cost	$	17	$	19	$	4	$	5
Interest cost		25		25		8		9
Expected return on assets		(25)		(27)		(14)		(14)
Amortization of:
Prior service cost (credit)		2		2		(1)		(2)
Actuarial loss		3		5		―		―
Regulatory adjustment		(21)		(24)		3		2
Total net periodic benefit cost	$	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 March 31, 2016:
Pension plans	$	15	$	2	$	―
Other postretirement benefit plans		1		―		―
Total expected contributions in 2016:
Pension plans	$	123	$	4	$	77
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 $432 million and $464 million at March 31, 2016 and December 31, 2015, respectively.

EARNINGS PER SHARE

The following table provides earnings per share (EPS) computations for the three months ended March 31, 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 March 31,
		2016		2015
Numerator:
Earnings/Income attributable to common shares		$	319	$	437
Denominator:
Weighted-average common shares outstanding for basic EPS(1)			249,734		247,722
Dilutive effect of stock options, restricted stock awards and restricted stock units			1,678		3,484
Weighted-average common shares outstanding for diluted EPS			251,412		251,206
Earnings per share:
Basic		$	1.28	$	1.76
Diluted		$	1.27	$	1.74
(1)	Includes 555 and 452 average fully vested restricted stock units held in our Deferred Compensation Plan for the three months ended March 31, 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.

The dilution from common stock options is based on the treasury stock method. Under this method, proceeds based on the exercise price plus unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits are tax deductions we would receive upon the assumed exercise of stock options in excess of the deferred income taxes we recorded related to the compensation expense on the stock options. Tax shortfalls occur when the assumed tax deductions are less than recorded deferred income taxes. The calculation of dilutive common stock equivalents excludes options for which the exercise price on common stock was greater than the average market price during the period (out-of-the-money options). For the three months ended March 31, 2016 and 2015, we had no such antidilutive stock options outstanding. For the three months ended March 31, 2016 and 2015, we had no stock options outstanding that were antidilutive because of the unearned compensation and windfall tax benefits included in the assumed proceeds under the treasury stock method.

The dilution from unvested restricted stock awards (RSAs) and restricted stock units (RSUs) is also based on the treasury stock method. Proceeds equal to the unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, related to the awards and units are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits or tax shortfalls recognized are the difference between tax deductions we would receive upon the assumed vesting of RSAs or RSUs and the deferred income taxes we recorded related to the compensation expense on such awards and units. There were no antidilutive RSAs or antidilutive RSUs from the application of unearned compensation in the treasury stock method for the three months ended March 31, 2016. There were no such antidilutive RSAs and 614 antidilutive RSUs for the three months ended March 31, 2015.

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 2,616,084 and 1,285,193 for the three months ended March 31, 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 and $8 million for the three months ended March 31, 2016 and 2015, respectively. Pursuant to our Sempra Energy share-based compensation plans, Sempra Energy’s compensation committee granted 372,270 TSR RSUs, 94,550 EPS RSUs and 93,256 service-based RSUs during the three months ended March 31, 2016, primarily in January.

During the three months ended March 31, 2016, IEnova issued 183,970 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 ended March 31, 2016 and 2015.

CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Three months ended March 31,
	2016		2015
Sempra Energy Consolidated:
AFUDC related to debt	$	7	$	6
AFUDC related to equity		27		27
Other capitalized interest		18		17
Total Sempra Energy Consolidated	$	52	$	50
SDG&E:
AFUDC related to debt	$	4	$	3
AFUDC related to equity		11		8
Total SDG&E	$	15	$	11
SoCalGas:
AFUDC related to debt	$	3	$	3
AFUDC related to equity		10		9
Total SoCalGas	$	13	$	12

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)
		Three months ended March 31, 2016 and 2015
		Foreign						Total
		currency				Pension and other		accumulated other
		translation		Financial		postretirement		comprehensive
		adjustments		instruments		benefits		income (loss)
2016:
Balance as of December 31, 2015		$	(582)	$	(137)	$	(87)	$	(806)
Other comprehensive income (loss) before
reclassifications			68		(82)		―		(14)
Amounts reclassified from accumulated other
comprehensive income			―		(2)		1		(1)
Net other comprehensive income (loss)			68		(84)		1		(15)
Balance as of March 31, 2016		$	(514)	$	(221)	$	(86)	$	(821)
2015:
Balance as of December 31, 2014		$	(322)	$	(90)	$	(85)	$	(497)
Other comprehensive loss before
reclassifications			(62)		(54)		―		(116)
Amounts reclassified from accumulated other
comprehensive income			―		(1)		1		―
Net other comprehensive (loss) income			(62)		(55)		1		(116)
Balance as of March 31, 2015		$	(384)	$	(145)	$	(84)	$	(613)
(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)
		Amounts reclassified
Details about accumulated		from accumulated other				Affected line item on Condensed
other comprehensive income (loss) components		comprehensive income (loss)				Consolidated Statements of Operations
		Three months ended March 31,
		2016		2015
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments		$	4	$	6	Interest Expense
Interest rate instruments			3		3	Equity (Losses) Earnings, Before Income Tax
Interest rate and foreign exchange instruments			1		―	Equity Earnings, Net of Income Tax
Commodity contracts not subjectto rate recovery			(7)		(7)	Revenues: Energy-Related Businesses
Total before income tax			1		2
			―		1	Income Tax Expense
Net of income tax			1		3
			(3)		(4)	Earnings Attributable to Noncontrolling Interests
		$	(2)	$	(1)
Pension and other postretirement benefits:
Amortization of actuarial loss		$	2	$	2	See note (1) below
			(1)		(1)	Income Tax Expense
Net of income tax		$	1	$	1
Total reclassifications for the period, net of tax		$	(1)	$	―
SDG&E:
Financial instruments:
Interest rate instruments		$	3	$	3	Interest Expense
			(3)		(3)	Earnings Attributable to Noncontrolling Interest
Total reclassifications for the period		$	―	$	―
(1)	Amounts are included in the computation of net periodic benefit cost (see "Pension and Other Postretirement Benefits" above).

For the three months ended March 31, 2016 and 2015, Other Comprehensive Income (Loss) (OCI), excluding amounts attributable to noncontrolling interests, at SDG&E and SoCalGas was negligible, and reclassifications out of AOCI to Net Income were also negligible for SoCalGas.

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS

The following tables provide reconciliations of changes in Sempra Energy’s and SDG&E’s shareholders’ equity and noncontrolling interests for the three months ended March 31, 2016 and 2015. The only change in SoCalGas’ equity for the three months ended March 31, 2016 and 2015 was comprehensive income and a negligible amount of preferred stock dividends declared.

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
			Sempra Energy		Non-
			shareholders’		controlling		Total
			equity		interests(1)		equity
Balance at December 31, 2015		$	11,809	$	770	$	12,579
Comprehensive income			304		11		315
Share-based compensation expense			13		―		13
Common stock dividends declared			(188)		―		(188)
Issuances of common stock			28		―		28
Repurchases of common stock			(54)		―		(54)
Tax benefit related to share-based compensation			34		―		34
Distributions to noncontrolling interests			―		(3)		(3)
Balance at March 31, 2016		$	11,946	$	778	$	12,724
Balance at December 31, 2014		$	11,326	$	774	$	12,100
Comprehensive income			321		8		329
Share-based compensation expense			13		―		13
Common stock dividends declared			(173)		―		(173)
Issuances of common stock			30		―		30
Repurchases of common stock			(65)		―		(65)
Tax benefit related to share-based compensation			52		―		52
Distributions to noncontrolling interests			―		(5)		(5)
Balance at March 31, 2015		$	11,504	$	777	$	12,281
(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		Non-
		shareholder’s		controlling		Total
		equity		interest		equity
Balance at December 31, 2015	$	5,223	$	53	$	5,276
Comprehensive income (loss)		129		(1)		128
Distributions to noncontrolling interest		―		(1)		(1)
Balance at March 31, 2016	$	5,352	$	51	$	5,403
Balance at December 31, 2014	$	4,932	$	60	$	4,992
Comprehensive income		147		2		149
Distributions to noncontrolling interest		―		(3)		(3)
Balance at March 31, 2015	$	5,079	$	59	$	5,138

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 March 31, 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
		March 31,		December 31,			March 31,		December 31,
		2016		2015			2016		2015
SDG&E:
Otay Mesa VIE		100	%	100	%	$	51	$	53
Sempra South American Utilities:
Chilquinta Energía subsidiaries(1)		23.5 – 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		18.9		18.9			470		468
Sempra Natural Gas:
Bay Gas Storage Company, Ltd.		9.1		9.1			25		25
Liberty Gas Storage, LLC		23.2		23.2			14		14
Southern Gas Transmission Company		49.0		49.0			1		1
Total Sempra Energy						$	758	$	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.

TRANSACTIONS WITH AFFILIATES

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

AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
		March 31, 2016		December 31, 2015
Sempra Energy Consolidated:
Total due from various unconsolidated affiliates - current		$	7	$	6
Sempra South American Utilities(1):
Eletrans S.A. and Eletrans II S.A.:
4% Note(2)		$	76	$	72
Other related party receivables			1		―
Sempra Mexico(1):
Affiliate of joint venture with PEMEX:
Note due November 13, 2017(3)			3		3
Note due November 14, 2018(3)			42		42
Note due November 14, 2018(3)			34		34
Note due November 14, 2018(3)			8		8
Energía Sierra Juárez:
Note due June 15, 2018(4)			17		24
Sempra Natural Gas:
Cameron LNG JV			5		3
Total due from unconsolidated affiliates - noncurrent		$	186	$	186
Total due to various unconsolidated affiliates - current		$	(13)	$	(14)
SDG&E:
Total due from various unconsolidated affiliates - current		$	1	$	1
Sempra Energy		$	(35)	$	(34)
SoCalGas			(8)		(13)
Affiliate			(6)		(8)
Total due to unconsolidated affiliates - current		$	(49)	$	(55)
Income taxes due (to) from Sempra Energy(5)		$	(32)	$	28
SoCalGas:
Sempra Energy(6)		$	―	$	35
SDG&E			8		13
Total due from unconsolidated affiliates - current		$	8	$	48
Sempra Energy		$	(34)	$	―
Total due to unconsolidated affiliate - current		$	(34)	$	―
Income taxes due (to) from Sempra Energy(5)		$	(23)	$	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 at Chilquinta Energía.
(3)	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 450 basis points (4.94 percent at March 31, 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 (6.81 percent at March 31, 2016), to finance the first phase of the Energía Sierra Juárez wind project.
(5)	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.
(6)	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 March 31,
	2016		2015
REVENUES
Sempra Energy Consolidated	$	5	$	8
SDG&E		3		3
SoCalGas		17		19
COST OF SALES
Sempra Energy Consolidated	$	30	$	19
SDG&E		14		5

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 March 31,
		2016		2015
Sempra Energy Consolidated:
Allowance for equity funds used during construction		$	27	$	27
Investment gains(1)			10		9
Electrical infrastructure relocation income(2)			1		―
Gains on interest rate and foreign exchange instruments, net			3		―
Sale of other investments			1		―
Foreign currency transaction losses			(2)		(1)
Regulatory interest, net(3)			2		1
Sundry, net			7		3
Total		$	49	$	39
SDG&E:
Allowance for equity funds used during construction		$	11	$	8
Regulatory interest, net(3)			2		1
Sundry, net			1		―
Total		$	14	$	9
SoCalGas:
Allowance for equity funds used during construction		$	10	$	9
Sundry, net			―		(1)
Total		$	10	$	8
(1)	Represents investment gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
(2)	Income at Luz del Sur associated with the relocation of electrical infrastructure.
(3)	Interest on regulatory balancing accounts.

INCOME TAXES

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
			Effective				Effective
		Income tax	income			Income tax	income
		expense	tax rate			expense	tax rate
		Three months ended March 31,
		2016				2015
Sempra Energy Consolidated	$	142	31	%	$	163	27	%
SDG&E		72	36			88	37
SoCalGas		87	31			95	31

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, and deferred income tax benefit associated with the impairment of a book investment) are recorded in the interim period in which they actually occur, which can result in variability in income tax expense.

Sempra Energy’s income tax expense in the three months ended March 31, 2016 includes deferred income tax expense related to Sempra Mexico’s power plant held for sale, as we discuss in Note 3.

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 has similar flow-through treatment.

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 March 31, 2016, Sempra Energy Consolidated had an aggregate of $4.2 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 major components of which we detail below. Available unused credit on these lines at March 31, 2016 was approximately $3.1 billion. Our foreign operations have additional general purpose credit facilities aggregating $1.1 billion at March 31, 2016. Available unused credit on these lines totaled $876 million at March 31, 2016.

Sempra Energy

Sempra Energy has a $1 billion, five-year syndicated revolving credit agreement expiring in October 2020. Citibank, N.A. serves as administrative agent for the syndicate of 20 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 March 31, 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 March 31, 2016, Sempra Energy had no outstanding borrowings or letters of credit supported by the facility.

Sempra Global

Sempra Global has a $2.21 billion, five-year syndicated revolving credit agreement expiring in October 2020. Citibank, N.A. serves as administrative agent for the syndicate of 20 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 March 31, 2016, Sempra Energy was in compliance with this and all other financial covenants under the credit facility.

At March 31, 2016, Sempra Global had $879 million of commercial paper outstanding supported by the facility and $1.33 billion 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. JPMorgan Chase Bank, N.A. serves as administrative agent for the syndicate of 20 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 March 31, 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 March 31, 2016, SDG&E and SoCalGas had $166 million and $5 million, respectively, of commercial paper outstanding, supported by the facility. Available unused credit on the line at March 31, 2016 was $584 million and $745 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 aggregating $547 million U.S. dollar equivalent, expiring between 2016 and 2018. 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 March 31, 2016, Sempra South American Utilities was in compliance with this financial covenant under the credit facilities. At March 31, 2016, Sempra South American Utilities had outstanding borrowings of $165 million and bank guarantees of $15 million against the Peruvian facilities, and $255 million of available unused credit. There were no outstanding borrowings at March 31, 2016 under the $112 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, The Bank of Tokyo - Mitsubishi UFJ, LTD., The Bank of Nova Scotia and Sumitomo Mitsui Banking Corporation. At March 31, 2016, IEnova had $91 million of outstanding borrowings supported by the facility, and available unused credit on the line was $509 million.

WEIGHTED AVERAGE INTEREST RATES

The weighted average interest rates on the total short-term debt at Sempra Energy Consolidated were 1.12 percent and 1.09 percent at March 31, 2016 and December 31, 2015, respectively. At March 31, 2016, the weighted average interest rates on total short-term debt at SDG&E and SoCalGas were 1.02 percent and 0.40 percent, respectively. The weighted average interest rate on total short-term debt at SDG&E was 1.01 percent at December 31, 2015.

LONG-TERM DEBT

SDG&E

In April 2016, SDG&E notified bondholders that it intends to redeem, prior to maturity, certain outstanding long-term debt instruments with a total principal amount of $105 million. At March 31, 2016, the debt remains classified as long-term on Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets. These instruments have a coupon rate of 5 percent and a maturity date of December 2027. SDG&E expects to repay the debt in the second quarter of 2016.

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 and Sempra Natural Gas 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, power generation, and Sempra Natural Gas’ storage. 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 March 31, 2016 and December 31, 2015 as follows:

NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
			March 31,	December 31,
Segment and Commodity		Unit of measure	2016	2015
California Utilities:
SDG&E:
Natural gas		MMBtu(1)	60	70
Electricity		MWh(2)	―	1
Congestion revenue rights		MWh	33	36
SoCalGas – natural gas		MMBtu	―	1
Energy-Related Businesses:
Sempra Natural Gas – natural gas		MMBtu	39	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. 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 March 31, 2016 and December 31, 2015, the net notional amounts of our interest rate derivatives, excluding the cross-currency swaps discussed below, were:

INTEREST RATE DERIVATIVES
(Dollars in millions)
		March 31, 2016			December 31, 2015
		Notional debt		Maturities	Notional debt		Maturities
Sempra Energy Consolidated:
Cash flow hedges(1)		$	381	2016-2028	$	384	2016-2028
Fair value hedges			300	2016		300	2016
SDG&E:
Cash flow hedge(1)			312	2016-2019		315	2016-2019
(1)	Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.

FOREIGN CURRENCY DERIVATIVES

We utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and joint ventures. These cash flow hedges exchange our Mexican-peso denominated principal and interest payments into the U.S. dollar and swap Mexican variable interest rates for U.S. fixed interest rates.

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, we entered into foreign currency derivatives with a notional amount totaling $550 million.

At March 31, 2016 and December 31, 2015, the net notional amounts of our foreign currency derivatives were:

FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
	March 31, 2016			December 31, 2015
	Notional debt		Maturities	Notional debt		Maturities
Sempra Mexico:
Cross-currency swaps	$	408	2018-2023	$	408	2018-2023
Other foreign currency derivatives		550	2016		―	―

In addition, Sempra South American Utilities use foreign currency derivatives at its subsidiaries and joint ventures as a means to manage foreign currency rate risk. We discuss such swaps 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

Each Condensed Consolidated Balance Sheet reflects the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Condensed Consolidated Balance Sheets at March 31, 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)
		March 31, 2016
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price				Fixed-price		Fixed-price
			contracts		Other		contracts		contracts
			and other		assets:		and other		and other
			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Derivatives designated as hedging instruments:
Interest rate and foreign exchange instruments(3)		$	5	$	―	$	(15)	$	(166)
Derivatives not designated as hedging instruments:
Interest rate and foreign exchange instruments			3		―		―		―
Commodity contracts not subject to rate recovery			144		20		(144)		(9)
Associated offsetting commodity contracts			(135)		(9)		135		9
Associated offsetting cash collateral			―		―		7		―
Commodity contracts subject to rate recovery			23		51		(68)		(61)
Associated offsetting commodity contracts			(4)		(1)		4		1
Associated offsetting cash collateral			―		―		31		24
Net amounts presented on the balance sheet			36		61		(50)		(202)
Additional cash collateral for commodity contracts
not subject to rate recovery			20		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			32		―		―		―
Total(4)		$	88	$	61	$	(50)	$	(202)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)		$	―	$	―	$	(14)	$	(25)
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			20		51		(65)		(61)
Associated offsetting commodity contracts			(2)		(1)		2		1
Associated offsetting cash collateral			―		―		31		24
Net amounts presented on the balance sheet			18		50		(46)		(61)
Additional cash collateral for commodity contracts
not subject to rate recovery			2		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			30		―		―		―
Total(4)		$	50	$	50	$	(46)	$	(61)
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			3		―		(3)		―
Associated offsetting commodity contracts			(2)		―		2		―
Net amounts presented on the balance sheet			1		―		(1)		―
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	$	―	$	(1)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.
(4)	Normal purchase contracts previously measured at fair value are excluded.

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		December 31, 2015
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price				Fixed-price		Fixed-price
			contracts		Other		contracts		contracts
			and other		assets:		and other		and other
			derivatives(1)		Sundry		derivatives(2)		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 ended March 31 were:

FAIR VALUE HEDGE IMPACTS
(Dollars in millions)
			Pretax gain on derivatives
			recognized in earnings
			Three months ended March 31,
		Location	2016		2015
Sempra Energy Consolidated:
Interest rate instruments		Interest Expense	$	2	$	2
Interest rate instruments		Other Income, Net		―		1
Total(1)			$	2	$	3
(1)	There was no hedge ineffectiveness in either the three months ended March 31, 2016 or 2015. All other changes in the fair values of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and recorded in Other Income, Net.

CASH FLOW HEDGE IMPACTS
(Dollars in millions)
		Pretax (loss) gain					Pretax (loss) gain reclassified
		recognized in OCI					from AOCI into earnings
		(effective portion)					(effective portion)
		Three months ended March 31,					Three months ended March 31,
		2016		2015		Location	2016		2015
Sempra Energy Consolidated:
Interest rate and foreign
exchange instruments(1)		$	(11)	$	(18)	Interest Expense	$	(4)	$	(6)
						Equity (Losses) Earnings,
Interest rate instruments			(137)		(78)	Before Income Tax		(3)		(3)
Interest rate and foreign						Equity Earnings,
exchange instruments			(18)		―	Net of Income Tax		(1)		―
Commodity contracts not						Revenues: Energy-Related
subject to rate recovery			1		(1)	Businesses		7		7
Total(2)		$	(165)	$	(97)		$	(1)	$	(2)
SDG&E:
Interest rate instruments(1)(2)		$	(5)	$	(5)	Interest Expense	$	(3)	$	(3)
(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 ended March 31, 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. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts that are currently outstanding mature.

SoCalGas expects that negligible losses, which are 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.

For all forecasted transactions, the maximum remaining term over which we are hedging exposure to the variability of cash flows at March 31, 2016 is approximately 13 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 ended March 31 were:

UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
		Pretax gain (loss) on derivatives
		recognized in earnings
		Three months ended March 31,
	Location	2016		2015
Sempra Energy Consolidated:
Foreign exchange instruments	Other Income, Net	$	3	$	―
Foreign exchange instruments	Equity Earnings,
	Net of Income Tax		2		(1)
Commodity contracts not subject	Revenues: Energy-Related
to rate recovery	Businesses		(1)		3
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power		(12)		(20)
Commodity contracts subject
to rate recovery	Cost of Natural Gas		(1)		1
Total		$	(9)	$	(17)
SDG&E:
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power	$	(12)	$	(20)
SoCalGas:
Commodity contracts subject
to rate recovery	Cost of Natural Gas	$	(1)	$	1

CONTINGENT FEATURES

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

For Sempra Energy Consolidated, the total fair value of this group of derivative instruments in a net liability position is $6 million at both March 31, 2016 and December 31, 2015. At March 31, 2016, if the credit ratings of Sempra Energy were reduced below investment grade, $7 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 is $5 million at both March 31, 2016 and December 31, 2015. At March 31, 2016, if the credit ratings of SDG&E were reduced below investment grade, $6 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. We have not changed the valuation techniques or types of inputs we use to measure fair value during the three months ended March 31, 2016.

Recurring Fair Value Measures

The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at March 31, 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.

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 March 31, 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 March 31, 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 March 31, 2016
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	623	$	―	$	―	$	―	$	623
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			62		43		―		―		105
Municipal bonds			―		156		―		―		156
Other securities			―		190		―		―		190
Total debt securities			62		389		―		―		451
Total nuclear decommissioning trusts(2)			685		389		―		―		1,074
Interest rate and foreign exchange instruments			―		8		―		―		8
Commodity contracts not subject to rate recovery			1		19		―		20		40
Commodity contracts subject to rate recovery			―		1		68		32		101
Total		$	686	$	417	$	68	$	52	$	1,223
Liabilities:
Interest rate and foreign exchange instruments		$	―	$	181	$	―	$	―	$	181
Commodity contracts not subject to rate recovery			3		6		―		(7)		2
Commodity contracts subject to rate recovery			―		67		57		(55)		69
Total		$	3	$	254	$	57	$	(62)	$	252
		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 March 31, 2016
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	623	$	―	$	―	$	―	$	623
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			62		43		―		―		105
Municipal bonds			―		156		―		―		156
Other securities			―		190		―		―		190
Total debt securities			62		389		―		―		451
Total nuclear decommissioning trusts(2)			685		389		―		―		1,074
Commodity contracts not subject to rate recovery			―		―		―		2		2
Commodity contracts subject to rate recovery			―		―		68		30		98
Total		$	685	$	389	$	68	$	32	$	1,174
Liabilities:
Interest rate instruments		$	―	$	39	$	―	$	―	$	39
Commodity contracts not subject to rate recovery			1		―		―		(1)		―
Commodity contracts subject to rate recovery			―		66		57		(55)		68
Total		$	1	$	105	$	57	$	(56)	$	107
		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 March 31, 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 not subject to rate recovery		$	1	$	―	$	―	$	(1)	$	―
Commodity contracts subject to rate recovery			―		1		―		―		1
Total		$	1	$	1	$	―	$	(1)	$	1
		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 March 31,
	2016		2015
Balance as of January 1	$	19	$	107
Realized and unrealized (losses) gains		(1)		6
Settlements		(7)		(11)
Balance as of March 31	$	11	$	102
Change in unrealized (losses) gains relating to
instruments still held at March 31	$	(1)	$	1

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 March 31, 2016, these electricity forward prices range from $15.85 per MWh to $57.43 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 March 31, 2016 and December 31, 2015:

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
		March 31, 2016
		Carrying		Fair value
		amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Noncurrent due from unconsolidated affiliates(1)		$	173	$	―	$	92	$	72	$	164
Total long-term debt(2)(3)			13,761		―		14,363		652		15,015
Preferred stock of subsidiary			20		―		23		―		23
SDG&E:
Total long-term debt(3)(4)		$	4,285	$	―	$	4,517	$	312	$	4,829
SoCalGas:
Total long-term debt(5)		$	2,513	$	―	$	2,731	$	―	$	2,731
Preferred stock			22		―		25		―		25
		December 31, 2015
		Carrying		Fair value
		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 $13 million and $11 million at March 31, 2016 and December 31, 2015, respectively.
(2)	Before reductions for unamortized discount (net of premium) and debt issuance costs of $106 million and $107 million at March 31, 2016 and December 31, 2015, respectively, and excluding build-to-suit and capital lease obligations of $386 million and $387 million at March 31, 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 $312 million and $315 million at March 31, 2016 and December 31, 2015, respectively, related to Otay Mesa VIE.
(4)	Before reductions for unamortized discount and debt issuance costs of $43 million at March 31, 2016 and December 31, 2015, and excluding capital lease obligations of $243 million and $244 million at March 31, 2016 and December 31, 2015, respectively.
(5)	Before reductions for unamortized discount and debt issuance costs of $24 million at March 31, 2016 and December 31, 2015, and excluding capital lease obligations of $1 million at March 31, 2016 and December 31, 2015.

We base the fair value of certain noncurrent amounts due from unconsolidated affiliates, long-term debt and preferred stock 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 Natural Gas – Rockies Express

In March 2016, Sempra Natural Gas agreed to sell its 25-percent interest in Rockies Express to a subsidiary of Tallgrass Development, LP for cash consideration of $440 million, subject to adjustment at closing. We consider the sale price for our equity interest in Rockies Express to be a market participants’ view of the total value of Rockies Express and have measured the fair value of our investment based on the equity sale price. In March 2016, we recorded a noncash impairment of our investment in Rockies Express of $44 million ($27 million after-tax), which is included in Equity Earnings, Before Income Tax, on the Condensed Consolidated Statement of Operations for the three months ended March 31, 2016. 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 non-recurring fair value measures related to our investment in Rockies Express:

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		Estimated				Fair	% of	Inputs used to
		fair				value	fair value	develop	Range of
		value			Valuation technique	hierarchy	measurement	measurement	inputs
Investment in
Rockies Express		$	440	(1)	Market approach	Level 2	100%	Equity sale price	100%
(1)	At measurement date of March 29, 2016. At March 31, 2016, our investment in Rockies Express had a carrying value of $436 million, reflecting subsequent equity method activity to record a distribution.

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

The replacement steam generators were designed and provided by 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. 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 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 to the SONGS OII proceeding (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. SDG&E is unable to determine what actions the CPUC will take, if any, in response to the A4NR PFM.

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 recent 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. SDG&E is unable to determine what actions the CPUC will take, if any, in response to the ORA PFM.

Accounting and Financial Impacts

Through December 31, 2015 and March 31, 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 in the first quarter of 2015 based on the CPUC’s approval in March 2015 of SDG&E’s compliance filing and establishment of the SONGS settlement revenue requirement.

The regulatory asset for the expected recovery of SONGS costs, consistent with the Amended Settlement Agreement, is $243 million ($43 million current and $200 million long-term) at March 31, 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 began on February 1, 2012. However, since the CPUC’s final decision approving the Amended Settlement Agreement was not issued until November 2014, amortization did not commence until January 2015.

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 March 31, 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 July 2015, the CPUC authorized SDG&E’s request to access trust funds for up to $55 million in decommissioning costs incurred in 2013, including $18 million that is expected to be withdrawn pending satisfactory 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 clarification will be provided.

In November 2015, the CPUC authorized SDG&E’s request to access trust funds for $36 million for SONGS Units 2 and 3 decommissioning costs incurred in 2014, including $13 million that also will be withdrawn pending satisfactory clarification by the IRS. SDG&E expects to request and receive approval in the second quarter of 2016 to access trust funds for Units 2 and 3 decommissioning costs incurred in 2015.

In April 2016, the CPUC adopted a decision approving a total decommissioning cost estimate for SONGS Units 2 and 3 of $4.411 billion, 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.

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.

Nuclear Decommissioning Trusts

The amounts collected in rates for SONGS’ decommissioning are invested in 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)
					Gross		Gross		Estimated
					unrealized		unrealized		fair
			Cost		gains		losses		value
At March 31, 2016:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies(1)		$	101	$	4	$	―	$	105
Municipal bonds(2)			146		10		―		156
Other securities(2)			192		6		(8)		190
Total debt securities			439		20		(8)		451
Equity securities			214		413		(4)		623
Cash and cash equivalents			9		―		(1)		8
Total		$	662	$	433	$	(13)	$	1,082
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 2016-2065.
(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 March 31,
		2016		2015
Proceeds from sales(1)		$	93	$	94
Gross realized gains			3		2
Gross realized losses			(8)		(4)
(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.

We provide additional information about SONGS in Note 11.

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. These filings requested revenue requirement increases of $133 million and $256 million for SDG&E and SoCalGas, respectively, over their 2015 revenue requirements.

In September 2015, the California Utilities filed settlement agreements with the CPUC that resolve all material matters related to the proceeding, except for the revenue requirement implications of certain income tax benefits associated with flow-through repair allowance tax deductions, discussed below. The settlement agreements are with eight of eleven intervening parties. For SoCalGas, the settlement proposes a total revenue requirement in 2016 of $2.219 billion, which is $133 million less than its original request. The proposed settlement represents an increase of $122 million, or 6 percent, over the 2015 total revenue requirement. For SDG&E, the settlement proposes a total revenue requirement in 2016 of $1.811 billion, which is $100 million less than its original request (as revised). The proposed settlement represents an increase of $17 million, or one percent, over the 2015 total revenue requirement. This increase reflects a $16 million adjustment to the 2015 estimated revenue requirement since the November 2014 filings. The filed settlement agreements also call for attrition adjustments of 3.5 percent for both 2017 and 2018. Because the 2016 settlement has not been finalized, the California Utilities will collect rates identical to 2015 authorized amounts until a 2016 decision is approved.

The California Utilities also filed a separate agreement, reached with ORA, proposing that a fourth year (2019) be added to the GRC period, with a revenue requirement increase of 4.3 percent over 2018. On April 29, 2016, the CPUC issued a proposed decision in a separate proceeding denying the potential of four-year GRC cycles citing that an extension to the GRC period would delay the implementation of the risk-based decision making framework.

The settlement agreements described above exclude a proposal, for both SDG&E and SoCalGas, regarding certain intra-rate case income tax benefits. The proposal recommends that the CPUC adjust SoCalGas’ rate base by $92 million and SDG&E’s rate base by $93 million, and additionally reduce both utilities’ revenue requirements by amounts tracked in tax memorandum accounts for the year 2015, which total $74 million for SoCalGas and $39 million for SDG&E. We believe the proposed treatment would violate and contradict long standing rate making and income tax policy, and would represent a material departure from historical practice. If this proposal is adopted, the outcome would reduce the revenue requirement amounts agreed to in the respective settlement agreements described above. SDG&E and SoCalGas do not expect that the prospective reduction to rate base described above would result in an immediate earnings impact if this proposal is adopted. However, if this proposal is adopted, SDG&E and SoCalGas may record a material charge against earnings for amounts in the tax memorandum accounts when the proposed decision is received.

We anticipate all matters to be resolved in the CPUC’s final decision on the 2016 GRC proceeding. We expect the CPUC to issue a final decision in the proceeding in the second quarter of 2016.

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 March 31, 2016, SDG&E and SoCalGas have recorded PSEP costs of $12 million and $177 million, respectively, in the CPUC-authorized regulatory account. In regard to requesting recovery from customers for PSEP costs incurred and recorded in accordance with the Triennial Cost Allocation Proceeding (TCAP) decision, SDG&E and SoCalGas are authorized to file an application with the CPUC for recovery of such costs up to the date of the TCAP decision and then annually for costs incurred through the end of each calendar year beginning with the period ended December 31, 2015. SoCalGas and SDG&E currently expect to file such applications no later than the second quarter of the year following and would expect a decision from the CPUC approximately 12 to 18 months following the date of the application (i.e., a decision on the recovery of costs recorded in the PSEP regulatory accounts as of December 31, 2015 would be expected by mid-2017).

In October 2014, SDG&E and SoCalGas filed a PFM 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 in a subsequent year. This request is pending at the CPUC.

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 and, as a result, are now requesting recovery of $0.1 million and $26.8 million, respectively. 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. We expect a decision on this application in the second quarter of 2016.

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. Through March 31, 2016, the after-tax disallowed costs for SoCalGas and SDG&E are $2.6 million and $0.5 million, respectively. In January 2016, SoCalGas and SDG&E jointly filed a request with the CPUC seeking rehearing of its December 2015 decision. A CPUC decision on the rehearing request is expected in 2016.

SDG&E MATTERS

SONGS

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

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 Federal Energy Regulatory Commission (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, a ruling was issued 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. 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. On April 21, 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 $23.1 million of wildfire damage expenses.

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

SOCALGAS MATTERS

Aliso Canyon Natural Gas Storage Facility

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

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
§	In April 2016, the CPUC issued a proposed decision finding that there is a need for enhanced system reliability for the southern portion of the SoCalGas and SDG&E gas system, but concluding that the utilities have failed to demonstrate that there is a need for their proposed pipeline project. Instead, the proposed decision determines that certain non-physical alternatives will provide enhanced supply reliability, without the need to construct pipeline facilities.
§	At March 31, 2016, SoCalGas has approximately $23 million of development costs invested in the project, classified as Property, Plant and Equipment on Sempra Energy's and SoCalGas' Condensed Consolidated Balance Sheets. Some or all of these assets could become impaired if the project and potential alternative uses for these assets were ultimately rejected by the CPUC. SoCalGas and SDG&E filed comments with the CPUC in April 2016.
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 March 2016, the U.S. Forest Service issued a final decision authorizing issuance of the CNF Master Special Use Permit renewing SDG&E's land rights and authorizing the construction, operation and maintenance of facilities located on national forest lands for the next 50 years, as well as approving the majority of the fire-hardening activities proposed by SDG&E.
§	Proposed decision issued by the CPUC in April 2016, which granted SDG&E a permit to construct. Final CPUC decision expected in the second quarter of 2016.
Sycamore-Peñasquitos Transmission Project
§	March 2016 final environmental impact report (EIR) recommended an alternative that undergrounds more of the project than originally proposed, and is viewed as environmentally superior. The CPUC may consider this alternative.
§	CPUC's recommended alternative has an estimated cost of $250 million to $300 million, compared to the original project cost estimate of $120 million to $150 million, and would also delay the project schedule by approximately 10 months.
§	CPUC decision expected in the second half of 2016.
South Orange County Reliability Enhancement
§	CPUC issued its final 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.
§	Final CPUC decision expected in the second half of 2016.

NOTE 11. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

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

At March 31, 2016, Sempra Energy’s accrued liabilities for legal proceedings, including associated legal fees and costs of litigation, on a consolidated basis, were $37 million. At March 31, 2016, accrued liabilities for legal proceedings for SDG&E and SoCalGas were $29 million and $6 million, respectively, excluding amounts 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 case remains subject to a damages-only trial, where the value of any compensatory damages resulting from the fires will be determined. Two appeals are 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 March 31, 2016, Sempra Energy and SDG&E have recorded assets of $363 million in Other Regulatory Assets (long-term) on their Condensed Consolidated Balance Sheets, including $360 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 March 31, 2016, the resulting after-tax charge against earnings would have been up to approximately $213 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 seeks injunctive relief and recovery of unspecified amounts of damages. The MDL court has finished ruling on pre-trial matters, and SDG&E expects that it will return the case to the Southern District of California.

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.

Investment in 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 are 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 received a closing notice from the project developer indicating that all such conditions had been met. SDG&E responded to the closing notice asserting that the contractual conditions had not been satisfied. On December 19, 2013, SDG&E filed a complaint against the project developer in San Diego Superior Court, asking that the court determine that SDG&E is entitled to terminate both the investment contract and the power purchase agreement due to the project developer’s failure to satisfy certain conditions. The project developer filed a separate complaint against SDG&E in Montana state court asking that court to determine that SDG&E breached the investment contract and the power purchase agreement, and asking for several categories of relief, including requiring SDG&E to invest in the project, requiring SDG&E to continue performing under the power purchase agreement, and payment of damages.

On January 27, 2014, the Montana court ordered SDG&E to continue making payments under the power purchase agreement pending a hearing on the project developer’s preliminary injunction motion. On March 14, 2014, SDG&E notified the project developer that the investment agreement expired by its own terms because a closing had not occurred by that date. The project developer disputed SDG&E’s position. On March 28, 2014, SDG&E filed an amended complaint against the project developer in San Diego seeking damages and declaratory relief that SDG&E was entitled to terminate the power purchase agreement and to permit the investment agreement to expire. On April 25, 2014, the Montana court granted the project developer’s preliminary injunction motion to prevent SDG&E from terminating the power purchase agreement on the grounds that the project developer would be irreparably harmed if the payments were not made while the parties’ respective rights were being determined in the litigation. The court did not rule on the merits of the parties’ claims. On July 18, 2014, the Montana Supreme Court determined that the parties’ contractual agreement to resolve any disputes in San Diego was mandatory, and ordered that the Montana action be dismissed. The San Diego court has scheduled a trial in May 2016. On February 11, 2016, SDG&E, the project developer and several of the project developer’s parent and affiliated entities entered into a conditional settlement agreement. Under the conditional 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. The conditional settlement agreement will not result in rate increases to SDG&E customers or a material impact on Sempra Energy’s or SDG&E’s financial condition, results of operations or cash flows. On February 16, 2016, SDG&E and the project developer filed a petition for approval of the settlement agreement with the CPUC. The conditional settlement agreement is not fully effective until approved by the CPUC; SDG&E expects a decision in 2016. The May 2016 trial date set in the San Diego court has been stayed until the settlement is addressed by the CPUC.

SoCalGas

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 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.

On December 24, 2015, by stipulation and court order, SoCalGas agreed to implement a formal plan for assisting residents in the nearby community to temporarily relocate, as well as to pay for additional overtime and costs associated with extra Los Angeles Police Department security patrols, among other things. SoCalGas has been providing temporary relocation support to residents in the nearby community who requested it before the well was permanently sealed. In addition, SoCalGas provided air filtration and purification systems to those residents in the nearby community requesting them.

As a result of receiving the confirmation from DOGGR that SS25 was permanently sealed, SoCalGas started winding down its temporary relocation support in accordance with the terms of the formal relocation plan. Subject to certain exceptions, the period for temporary relocation support to residents who temporarily relocated to short-term housing, such as hotels, was scheduled to end on February 25, 2016. This deadline was challenged by the County of Los Angeles (County), who expressed concern about potential lingering health effects and stated that they intended to perform indoor air testing. The California Superior Court issued an order extending such period for an additional 22 days for certain residents. On March 18, 2016, the County sought a further extension through the end of the litigation, which was denied, but the Superior Court stayed its order pending a potential appeal to the California Court of Appeal. Following an appeal by the County, on April 13, 2016, the Court of Appeal remanded the matter back to the California Superior Court for further consideration of the record and extended the relocation support term to at least April 27, 2016. The Superior Court set the matter for hearing on April 27, 2016, and gave the parties an opportunity to file supplemental briefing and evidence. On April 27, 2016, the Superior Court heard oral argument on the matter and ultimately entered an order further extending the relocation support term pending the completion of the County’s indoor testing. The Superior Court set a case management conference on June 7, 2016, for further consideration of the relocation program, and instructed the County and SoCalGas to file a joint update with the Court on May 31, 2016 regarding the status of the relocation support.

To put the relocation dispute in perspective, on January 31, 2016, the Los Angeles County Department of Public Health (LA County DPH) stated, “The average levels of benzene and other trace chemicals that have been measured in the community are currently at or below levels seen elsewhere in the county, and do not pose an increase in the risk of short‐term or long‐term health effects.” Following the sealing of the well, included in its April 9, 2016 update to its Aliso Canyon webpage, the LA County DPH affirmed that “levels of chemicals of concern are now consistent with expected background levels for the Los Angeles air basin.”

In seeking the extension of the relocation support term, the County has contended that indoor testing is required in order to determine whether it is safe for residents to return home. On March 24, 2016, the County released its indoor sampling work plan to test approximately 100 houses for a broad range of chemicals, including volatile organic compounds, semi-volatile organic compounds, metals, and sulfur compounds in the air and on surfaces. These substances are commonly found in households at varying levels. We were informed that this testing was completed on April 8, 2016, and that the County is currently analyzing the results. The County has reported that it anticipates completing its analysis and releasing a final report by late May 2016. In mid-March 2016, a third party engaged by SoCalGas conducted screening of indoor air for methane and mercaptans (odorants added to natural gas) in 71 houses in the Porter Ranch community near the Aliso Canyon storage facility. Based on this screening, no mercaptans were detected, and concentrations of methane were well below levels of concern as established by the California Environmental Protection Agency’s Department of Toxic Substances Control.

The total costs incurred to remediate and stop the leak and to mitigate local community impacts will be significant, and to the extent not covered by insurance, or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Cost Estimates and Accounting Impact. At March 31, 2016, SoCalGas recorded estimated costs of $665 million related to the leak. Of this amount, approximately 70 percent is for the temporary relocation program and approximately 15 percent is for attempts 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 amount includes estimated legal costs necessary to defend litigation, the value of lost gas, the costs to mitigate the actual natural gas released, and other costs. 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. The $665 million represents management’s best estimate of these costs related to the leak. Of these costs, certain amounts have been paid and $302 million is recorded as Reserve for Aliso Canyon Costs at March 31, 2016 on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets for amounts expected to be paid after March 31, 2016. We will refine these estimates as further information becomes available. SoCalGas’ estimate of temporary relocation costs was primarily determined considering the current experience of temporary relocations through the hearing date of April 27, 2016 discussed above. The remainder of the reserve was estimated primarily based on work plans, the rate of cost accumulation and estimated duration of the various activities, or other estimates. Any differences in actual costs incurred will impact these estimates. Based on the order of the Superior Court on April 27, 2016, which scheduled the next hearing on June 7, 2016, for purposes of this estimate we assume the period for temporary relocation support to residents who temporarily relocated has been extended to June 7, 2016. While such support period could end before June 7, 2016, due to the fact that temporary relocation support has been extended several times, there can be no assurance that future extensions will not be granted. The cost of the temporary relocation support is significant, and the costs of any further extensions of the relocation support term, which are not included in our estimate, could result in a material increase in our cost estimate.

At March 31, 2016, we recorded the expected recovery of the costs described in the immediately preceding paragraph related to the leak (less insurance retentions) of $660 million as Insurance Receivable for Aliso Canyon Costs on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets. 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.

The above amounts do not include any damage awards, restitution, or any civil 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 estimated at this time. In addition, the above amounts do not include other potential costs that we currently do not anticipate incurring or we cannot reasonably estimate.

On March 17, 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, on March 24, 2016, 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 TURN and SCGC. On April 22, 2016, the CPUC’s Energy Division issued a suspension notice for SoCalGas’ advice letter citing the need for additional time for staff review. This suspension period could last up to 120 days.

Insurance.We have at least four kinds of insurance policies that provide in excess of $1 billion in insurance coverage. 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, 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 estimated costs to mitigate the actual natural gas released, the costs associated with litigation and claims by nearby residents and businesses, and, in some circumstances depending on their nature and manner of assessment, fines and penalties. We have been communicating with our insurance carriers and intend to pursue the full extent of our insurance coverage. 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 at March 31, 2016 of $665 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, 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, the costs not included in the $665 million estimate could be material, and to the extent not covered by insurance, could have a material adverse effect on Sempra Energy’s and SoCalGas’ cash flows, financial condition and results of operations.

Governmental Investigations and Civil and Criminal Litigation. Various governmental agencies, including the DOGGR, LA County DPH, South Coast Air Quality Management District (SCAQMD), California Air Resources Board (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 District Attorney’s Office and California Attorney General’s Office, are investigating this incident. On January 25, 2016, the DOGGR and CPUC selected Blade Energy Partners 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 late 2016 or early 2017, but the timing is dependent on the DOGGR and the CPUC.

As of April 28, 2016, 138 lawsuits have been filed (134 in Los Angeles County Superior Court, 2 in San Diego County Superior Court, and 2 in the United States District Court for the Southern District of California) against SoCalGas, some of which have also named Sempra Energy, and, in derivative and securities law claims on behalf of Sempra Energy and/or SoCalGas, certain officers and directors of Sempra Energy and/or SoCalGas. These various lawsuits assert causes of action for negligence, strict liability, property damage, fraud, nuisance, trespass, breach of fiduciary duties, and violation of federal securities laws, among other things, and additional litigation may be filed against us in the future related to this incident. Many of these complaints seek class action status, compensatory and punitive damages, injunctive relief, and attorneys’ fees. The Los Angeles City Attorney and Los Angeles County Counsel have also filed a complaint on behalf of the people of the State of California against SoCalGas for public nuisance and violation of the California Unfair Competition Law. The California Attorney General, acting in her independent capacity and on behalf of the people of the State of California and the CARB, joined this lawsuit. The complaint, which as amended includes the California Attorney General, adds allegations of 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 also 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 February 2, 2016, the Los Angeles 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 violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public.

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, could be significant and to the extent not covered by insurance, 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 implemented orders to stop the leak and implements various other orders with respect to:

§   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, the CPUC, the CARB and the California Energy Commission 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 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 preliminarily assumes that the leak released approximately 100,000 metric tons of methane. It 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 8,000,000 metric tons of carbon dioxide equivalent. CARB’s program also requires all of the mitigation to occur in California over the next five to ten years without the use of allowances or offsets. We have not agreed to this proposed formulation 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.

On April 1, 2016, the Secretary of the U.S. Department of Energy (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. PHMSA has indicated plans to initiate additional regulatory actions on natural gas storage nationally. Each of the DOGGR, SCAQMD, EPA and CARB has commenced separate rulemaking proceedings to adopt further regulations covering natural gas storage facilities and injection wells. The U.S. Senate also passed two pieces of legislation, which include a provision requiring the establishment of an Aliso Canyon Task Force. This generally mirrors the focus and structure of the Task Force on Natural Gas Storage Safety. The legislation requires the Task Force to examine a specific set of issues related to the leak, including impacts on health and electricity prices.

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. 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 regulations.

On April 22, 2016, DOSH issued notices of intent to issue four “serious” citations to SoCalGas, alleging violations of Title 8 of the California Code of Regulations sections 5155(e)(1), 5192(q)(6)(E), 6845(a), and 6851(a). The notices allege (1) a failure to monitor concentrations of airborne contaminant exposure to employees, (2) an Incident Commander did not receive sufficient training, (3) insufficient testing and inspection of well casing and tubing and (4) insufficient inspection and maintenance to prevent leaks. The maximum penalty that DOSH could issue for these four alleged violations is a total of $280,000.

Natural Gas Storage Operations. SoCalGas estimates that approximately 57 billion cubic feet (Bcf) of natural gas has been delivered to customers or moved to other gas storage facilities from an initial starting point of approximately 77 Bcf of gas in storage on October 23, 2015 at the Aliso Canyon facility. The CPUC has directed SoCalGas to maintain a minimum of 15 Bcf of working natural gas to help ensure reliability of the system through the spring and summer months, and based on the CARB estimates of lost gas, the facility is approximately at this level. 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. SoCalGas is in the process of conducting a measurement of natural gas lost from the leak and will provide that information to the relevant regulatory bodies.

Natural gas withdrawn from storage is important for service reliability during peak demand periods, including heating needs in the winter, as well as peak electric generation needs in the summer. Aliso Canyon, with a storage capacity of 86 Bcf, is the largest storage facility and an important element of SoCalGas’ delivery system. Aliso Canyon represents 63 percent of SoCalGas’ owned natural gas storage capacity. SoCalGas has not injected natural gas into Aliso Canyon since October 25, 2015, in accordance with the Governor’s Order and subject to contrary CPUC reliability-based direction. 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 the completion of this review and any necessary approvals have been obtained.

On April 5, 2016, four energy agencies—the CPUC, the California Energy Commission, the California Independent System Operator, and the Los Angeles Department of Water and Power—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; the Greater Los Angeles region could face an estimated 16 days of gas curtailments this upcoming summer—assuming no withdrawals of any of the 15 Bcf held at Aliso Canyon; and unless gas is withdrawn from Aliso Canyon, 14 of these days are likely to be large enough to interrupt electric generators located in the LA Basin. 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 this upcoming summer. The procedures, which would address supply shortages and surpluses using temporarily modified Operational Flow Order (OFO) tariff provisions, would be in place through no later than November 30, 2016. SoCalGas, SDG&E, and the other settlement parties have asked the CPUC to approve this package of reliability-related provisions by May 26, 2016. There can be no assurance that these measures, if approved, will prevent gas curtailments or power outages during the period Aliso Canyon remains offline.

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 March 31, 2016, the Aliso Canyon facility has a net book value of $415 million, including $180 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. Sempra Mexico expects additional Mexican court proceedings and governmental actions regarding the claimant’s assertions as to whether the terminal’s permits should be modified or revoked in any manner.

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. In November 2015, the Agrarian Court denied Sempra Mexico’s challenge, but the ruling does not affect any property rights. Another appeal filed by SEDATU is pending. 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.

Sempra Natural Gas

Since April 2012, a total of 14 lawsuits have been 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. Eleven of the lawsuits have been settled. The remaining three lawsuits, which include approximately 250 individual plaintiffs, allege nuisance, fraud and negligence causes of action, and seek unspecified compensatory and punitive damages.

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. A preliminary hearing is scheduled for September 19 to 21, 2016. 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 £156 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 March 31, 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 should the liability from the final resolution of these matters be greater than the reserves related to Sempra Commodities. 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 COMMITMENTS

We discuss below significant changes in the first three months of 2016 to contractual commitments discussed in Note 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 $46 million since December 31, 2015, primarily due to payments on existing contracts and changes in forward natural gas prices in the first three months of 2016. Net future payments are expected to decrease by $60 million in 2016, and increase by $10 million in 2017 and $4 million in 2018 compared to December 31, 2015.

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 three months of 2016, is expected to decrease by $146 million in 2016, $3 million in 2017, $7 million in 2018, $18 million in 2019, and $30 million in 2020 and increase by $20 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 per year beyond 2028 through contract termination 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.

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’scontribution 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. SDG&E’s share of the settlement is approximately $32 million.

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, Peru, southwest Alabama, and Hattiesburg, Mississippi.

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.

4.   Sempra Mexico develops, owns and operates, or holds interests in, natural gas transmission pipelines and propane and ethane systems, a natural gas distribution utility, electric generation facilities (including wind), 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 Termoeléctrica de Mexicali natural gas-fired power plant located in Mexicali, Baja California, as discussed 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, Minnesota, Nebraska, Nevada and Pennsylvania to serve wholesale electricity markets in the United States.

6.   Sempra Natural Gas develops, owns and operates, or holds interests in, natural gas pipelines and storage facilities, natural gas distribution utilities and a terminal for the import and export of LNG and sale of natural gas, all within the United States. 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 March 31,
	2016				2015
REVENUES
SDG&E	$	991	38	%	$	966	36	%
SoCalGas		1,033	40			1,048	39
Sempra South American Utilities		400	15			389	15
Sempra Mexico		138	5			163	6
Sempra Renewables		7	―			8	―
Sempra Natural Gas		130	5			197	7
Intersegment revenues(1)		(77)	(3)			(89)	(3)
Total	$	2,622	100	%	$	2,682	100	%
INTEREST EXPENSE
SDG&E	$	48			$	52
SoCalGas		22				19
Sempra South American Utilities		9				5
Sempra Mexico		4				5
Sempra Renewables		―				1
Sempra Natural Gas		12				21
All other		72				63
Intercompany eliminations		(24)				(32)
Total	$	143			$	134
INTEREST INCOME
Sempra South American Utilities	$	5			$	4
Sempra Mexico		2				2
Sempra Renewables		1				―
Sempra Natural Gas		16				19
Intercompany eliminations		(18)				(18)
Total	$	6			$	7
DEPRECIATION AND AMORTIZATION
SDG&E	$	159	49	%	$	145	48	%
SoCalGas		122	37			113	37
Sempra South American Utilities		13	4			13	4
Sempra Mexico		17	5			17	6
Sempra Renewables		1	―			2	1
Sempra Natural Gas		13	4			12	4
All other		3	1			1	―
Total	$	328	100	%	$	303	100	%
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	72			$	88
SoCalGas		87				95
Sempra South American Utilities		14				16
Sempra Mexico		41				8
Sempra Renewables		(12)				(17)
Sempra Natural Gas		(25)				2
All other		(35)				(29)
Total	$	142			$	163

SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
		Three months ended March 31,
		2016				2015
EQUITY EARNINGS (LOSSES)
Earnings (losses) recorded before tax:
Sempra Renewables		$	7			$	2
Sempra Natural Gas			(29)				17
Total		$	(22)			$	19
Earnings (losses) recorded net of tax:
Sempra South American Utilities		$	2			$	(1)
Sempra Mexico			15				16
Total		$	17			$	15
EARNINGS (LOSSES)
SDG&E		$	129	40	%	$	147	34	%
SoCalGas(2)			195	61			214	49
Sempra South American Utilities			38	12			41	9
Sempra Mexico			17	5			47	11
Sempra Renewables			13	4			13	3
Sempra Natural Gas			(36)	(11)			2	―
All other			(37)	(11)			(27)	(6)
Total		$	319	100	%	$	437	100	%
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E		$	329	34	%	$	355	46	%
SoCalGas			340	35			315	40
Sempra South American Utilities			43	4			31	4
Sempra Mexico			40	4			55	7
Sempra Renewables			181	19			3	1
Sempra Natural Gas			35	4			10	1
All other			3	―			11	1
Total		$	971	100	%	$	780	100	%
		March 31, 2016				December 31, 2015
ASSETS
SDG&E		$	16,625	40	%	$	16,515	40	%
SoCalGas			12,427	30			12,104	29
Sempra South American Utilities			3,434	8			3,235	8
Sempra Mexico			3,843	9			3,783	9
Sempra Renewables			1,454	3			1,441	4
Sempra Natural Gas			5,395	13			5,566	13
All other			741	2			734	2
Intersegment receivables			(2,084)	(5)			(2,228)	(5)
Total		$	41,835	100	%	$	41,150	100	%
EQUITY METHOD AND OTHER INVESTMENTS
Sempra South American Utilities		$	(2)			$	(4)
Sempra Mexico			522				519
Sempra Renewables			823				855
Sempra Natural Gas			1,308				1,460
All other			76				75
Total		$	2,727			$	2,905
(1)	Revenues for reportable segments include intersegment revenues of $3 million, $17 million, $27 million and $30 million for the three months ended March 31, 2016 and $2 million, $19 million, $25 million and $43 million for the three months ended March 31, 2015 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.
(2)	After preferred dividends.

NOTE 13. SUBSEQUENT EVENT

SEMPRA NATURAL GAS

In April 2016, Sempra Natural Gas signed a definitive agreement to sell the parent company of Mobile Gas and Willmut Gas. We expect to receive cash proceeds of approximately $323 million, subject to normal adjustments at closing, and the buyer will assume existing debt of approximately $67 million. In April 2016, we reclassified the assets and liabilities of Mobile Gas and Willmut Gas to held for sale. The transaction is subject to customary regulatory approvals, and we expect the sale to close in 2016.

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.

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 natural gas distribution utility §electric generation facilities, including wind §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	§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 pipelines and storage facilities §a terminal in the U.S. for the import and export of LNG and sale of natural gas §natural gas distribution utilities §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

Our earnings decreased by $118 million (27%) to $319 million in the three months ended March 31, 2016, while diluted earnings per share decreased by $0.47 per share (27%) to $1.27 per share.

The net changes in our earnings and diluted earnings per share were primarily due to the following decreases, by segment:

 SDG&E

§   $(14) million higher non-refundable operating costs, including depreciation and litigation, in 2016 with no corresponding increase in the CPUC-authorized margin due to the delay in the 2016 General Rate Case (GRC) decision; we discuss the 2016 GRC in Note 10 of the Notes to Condensed Consolidated Financial Statements herein

§   $(13) million decrease due to the plant closure adjustment recorded in 2015 based on the California Public Utilities Commission’s (CPUC) approval of a compliance filing related to SDG&E’s authorized recovery of its investment in the San Onofre Nuclear Generating Station (SONGS), as we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements herein

SoCalGas

§   $(12) million higher non-refundable operating costs, including depreciation and litigation, in 2016 with no corresponding increase in the CPUC-authorized margin due to the delay in the 2016 GRC decision

§   $(8) million after-tax gas cost incentive mechanism (GCIM) award approved by the CPUC in 2015

Sempra South American Utilities

§   $(4) million lower earnings from foreign currency translation and inflation effects

Sempra Mexico

§   $(24) million deferred tax expense on our investment in the Termoeléctrica de Mexicali natural gas-fired power plant as a result of management’s decision to hold the asset for sale, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein

§   $(4) million lower earnings, primarily due to positive foreign currency and inflation effects in 2015

Sempra Natural Gas

§   $(27) million impairment charge related to Sempra Natural Gas’ investment in Rockies Express Pipeline LLC (Rockies Express)

Parent and Other

§   $(10) million higher net interest expense, due primarily to debt offerings in 2015

The following table shows our earnings (losses) by segment, which we discuss below in “Segment Results.”

SEMPRA ENERGY EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)
		Three months ended March 31,
		2016				2015
California Utilities:
SDG&E		$	129	40	%	$	147	34	%
SoCalGas(1)			195	61			214	49
Sempra International:
Sempra South American Utilities			38	12			41	9
Sempra Mexico			17	5			47	11
Sempra U.S. Gas & Power:
Sempra Renewables			13	4			13	3
Sempra Natural Gas			(36)	(11)			2	―
Parent and other(2)			(37)	(11)			(27)	(6)
Earnings		$	319	100	%	$	437	100	%
(1)	After preferred dividends.
(2)	Includes after-tax interest expense ($43 million and $38 million for the three months ended March 31, 2016 and 2015, respectively), intercompany eliminations recorded in consolidation and certain corporate costs.

SEGMENT RESULTS

The following section is a discussion of earnings (losses) by Sempra Energy segment, as well as Parent and other, as presented in the table above. Variance amounts are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise noted.

EARNINGS BY SEGMENT – CALIFORNIA UTILITIES

(Dollars in millions)

Because a final decision for the 2016 GRC has not yet been issued by the CPUC, the California Utilities have recorded revenues in the three months ended March 31, 2016 based on levels authorized for 2015.

SDG&E

Our SDG&E segment recorded earnings of:

§   $129 million in the three months ended March 31, 2016

§   $147 million in the three months ended March 31, 2015

The decrease in earnings of $18 million (12%) in the three months ended March 31, 2016 was primarily due to:

§   $14 million higher non-refundable operating costs, including depreciation and litigation, in 2016 with no corresponding increase in the CPUC-authorized margin due to the delay in the 2016 GRC decision; and

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

§   $3 million increase in allowance for funds used during construction (AFUDC) related to equity;

§   $3 million lower generation major maintenance costs; and

§   $3 million lower interest expense.

SoCalGas

Our SoCalGas segment recorded earnings of:

§   $195 million in the three months ended March 31, 2016 (both before and after preferred dividends)

§   $214 million in the three months ended March 31, 2015 (both before and after preferred dividends)

The decrease in earnings of $19 million (9%) in the three months ended March 31, 2016 was primarily due to:

§   $12 million higher non-refundable operating costs, including depreciation and litigation, in 2016 with no corresponding increase in the CPUC-authorized margin due to the delay in the 2016 GRC decision;

§   $8 million after-tax GCIM award approved by the CPUC in 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; and

§   $2 million higher interest expense; offset by

§   $5 million higher returns associated with CPUC-approved capital projects both under construction and in service.

EARNINGS BY SEGMENT – SEMPRA INTERNATIONAL

(Dollars in millions)

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:

§   $38 million in the three months ended March 31, 2016

§   $41 million in the three months ended March 31, 2015

The decrease in earnings of $3 million (7%) in the three months ended March 31, 2016 was primarily due to:

§   $4 million lower earnings from foreign currency translation and inflation effects; and

§   $2 million lower capitalized interest due to completion of construction of the Santa Teresa hydroelectric power plant in September 2015; offset by

§   $3 million higher earnings from operations mainly due to the start of operations of the Santa Teresa hydroelectric power plant.

Sempra Mexico

Our Sempra Mexico segment recorded earnings of:

§   $17 million in the three months ended March 31, 2016

§   $47 million in the three months ended March 31, 2015

The decrease in earnings of $30 million in the three months ended March 31, 2016 was primarily due to:

§   $24 million deferred tax expense on our investment in Termoeléctrica de Mexicali as a result of management’s decision to hold the asset for sale, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein;

§   $4 million lower benefit due primarily to positive effects from foreign currency and inflation in 2015, 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;” and

§   $3 million lower AFUDC related to equity primarily due to completion of the first segment of the Sonora pipeline.

EARNINGS (LOSSES) BY SEGMENT – SEMPRA U.S. GAS & POWER

(Dollars in millions)

Sempra Renewables

Our Sempra Renewables segment recorded earnings of:

§   $13 million in the three months ended March 31, 2016

§   $13 million in the three months ended March 31, 2015

Earnings in the three months ended March 31, 2016 included $2 million higher earnings from increased production at wind projects, offset by $2 million lower solar investment tax credits from projects placed in service in 2015.

Sempra Natural Gas

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

§   $(36) million in the three months ended March 31, 2016

§   $2 million in the three months ended March 31, 2015

The change in the three months ended March 31, 2016 was primarily due to:

§   $27 million impairment charge related to the investment in Rockies Express, which we discuss further in Notes 3 and 8 of the Notes to Condensed Consolidated Financial Statements herein; and

§   $9 million lower results primarily from midstream marketing activities driven by changes in natural gas prices.

Parent and Other

Losses for Parent and Other were

§   $37 million in the three months ended March 31, 2016

§   $27 million in the three months ended March 31, 2015

The increase in losses of $10 million (37%) in the three months ended March 31, 2016 was primarily due to:

§   $10 million higher net interest expense, due primarily to debt offerings in 2015; and

§   $5 million of income tax benefits in 2015 related to our former commodities-marketing businesses; offset by

§   $7 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.

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 Service Corporation (Mobile Gas) and Willmut Gas Company (Willmut Gas)

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 March 31,
	2016		2015
Electric revenues:
SDG&E	$	843	$	805
Sempra South American Utilities		378		363
Eliminations and adjustments		(2)		(2)
Total		1,219		1,166
Natural gas revenues:
SoCalGas		1,033		1,048
SDG&E		148		161
Sempra Mexico		22		25
Sempra Natural Gas		38		42
Eliminations and adjustments		(18)		(20)
Total		1,223		1,256
Total utilities revenues	$	2,442	$	2,422
Cost of electric fuel and purchased power:
SDG&E	$	248	$	228
Sempra South American Utilities		267		253
Total	$	515	$	481
Cost of natural gas:
SoCalGas	$	253	$	267
SDG&E		39		54
Sempra Mexico		12		15
Sempra Natural Gas		11		15
Eliminations and adjustments		(4)		(5)
Total	$	311	$	346

Sempra Energy Consolidated

Electric Revenues

During the three months ended March 31, 2016, our electric revenues increased by $53 million (5%), remaining at $1.2 billion primarily due to:

§   $38 million increase at SDG&E, which included

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

□   $18 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance, and

□   $3 million higher authorized revenues from electric transmission; and

§   $15 million increase at Sempra South American Utilities, which included

□   $53 million due to higher rates at Luz del Sur and Chilquinta Energía, and

□   $7 million higher revenues from the Santa Teresa hydroelectric power plant, which began commercial operations in September 2015, offset by

□   $33 million due to foreign currency exchange rate effects, and

□   $14 million lower volumes at Luz del Sur.

Our utilities’ cost of electric fuel and purchased power increased by $34 million (7%) to $515 million in the three months ended March 31, 2016 due to:

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

§   $14 million increase at Sempra South American Utilities driven primarily by higher prices, offset by lower volumes and foreign currency exchange rate effects.

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 March 31, 2016, Sempra Energy’s natural gas revenues decreased by $33 million (3%) to $1.2 billion, and the cost of natural gas decreased by $35 million (10%) to $311 million. The decrease in natural gas revenues included

§   decreases in cost of natural gas sold at SoCalGas and SDG&E, as we discuss below;

§   $14 million GCIM award approved by the CPUC in February 2015 at SoCalGas; and

§   $5 million lower recovery of costs at SoCalGas associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; offset by

§   $12 million higher revenues at SoCalGas for returns associated with CPUC-approved capital projects both under construction and in service, including the Pipeline Safety Enhancement Plan (PSEP). We discuss the PSEP in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and below in “Factors Influencing Future Performance – California Utilities.”

We discuss the changes in revenues and 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 three months ended March 31, 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.

SDG&E
ELECTRIC DISTRIBUTION AND TRANSMISSION
(Volumes in millions of kilowatt-hours, dollars in millions)
		Three months ended March 31, 2016			Three months ended March 31, 2015
Customer class		Volumes	Revenue		Volumes	Revenue
Residential		1,689	$	339	1,712	$	346
Commercial		1,579		285	1,600		302
Industrial		488		73	497		79
Direct access		834		49	867		52
Street and highway lighting		17		3	23		4
		4,607		749	4,699		783
CAISO shared transmission revenue - net(1)				68			43
Other revenues				52			52
Balancing accounts				(26)			(73)
Total(2)			$	843		$	805
(1)	California Independent System Operator (CAISO).
(2)	Includes sales to affiliates of $2 million in each of 2016 and 2015.

For the three months ended March 31, 2016, SDG&E’s electric revenues increased by $38 million (5%) to $843 million compared to the corresponding period of 2015 primarily due to:

§   $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 consumption due to energy efficiency initiatives, including rooftop solar installations, and

□   a decrease in the cost of purchased power due to declining natural gas prices; and

§   $18 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; and

§   $3 million higher authorized revenues from electric transmission.

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 three months ended March 31, 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.

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
Three months ended March 31, 2016:
Residential		10	$	125	―	$	1	10	$	126
Commercial and industrial		4		30	3		5	7		35
Electric generation plants		―		―	5		1	5		1
		14	$	155	8	$	7	22		162
Other revenues										11
Balancing accounts										(25)
Total(1)									$	148
Three months ended March 31, 2015:
Residential		9	$	111	―	$	1	9	$	112
Commercial and industrial		4		30	2		4	6		34
Electric generation plants		―		―	6		―	6		―
		13	$	141	8	$	5	21		146
Other revenues										11
Balancing accounts										4
Total(1)									$	161
(1)	Includes sales to affiliates of $1 million in each of 2016 and 2015.

During the three months ended March 31, 2016, SDG&E’s natural gas revenues decreased by $13 million (8%) to $148 million, primarily due to cost of natural gas sold decreasing by $15 million (28%) to $39 million.

SDG&E’s average cost of natural gas for the three months ended March 31, 2016 was $2.67 per thousand cubic feet (Mcf) compared to $4.14 per Mcf for the corresponding period in 2015, a 36-percent decrease of $1.47 per Mcf, resulting in lower revenues and cost of $21 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 $6 million.

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
Three months ended March 31, 2016:									��
Residential		72	$	696	1	$	4	73	$	700
Commercial and industrial		27		180	71		66	98		246
Electric generation plants		―		―	33		7	33		7
Wholesale		―		―	35		6	35		6
		99	$	876	140	$	83	239		959
Other revenues										54
Balancing accounts										20
Total(1)									$	1,033
Three months ended March 31, 2015:
Residential		61	$	605	1	$	6	62	$	611
Commercial and industrial		25		178	72		59	97		237
Electric generation plants		―		―	33		7	33		7
Wholesale		―		―	41		8	41		8
		86	$	783	147	$	80	233		863
Other revenues										48
Balancing accounts										137
Total(1)									$	1,048
(1)	Includes sales to affiliates of $17 million in 2016 and $19 million in 2015.

During the three months ended March 31, 2016, SoCalGas’ natural gas revenues decreased by $15 million (1%), remaining at $1 billion, and the cost of natural gas sold decreased by $14 million (5%) to $253 million. The revenue decrease included

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

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

§   $5 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; offset by

§   $12 million higher revenues for returns associated with CPUC-approved capital projects both under construction and in service, including the PSEP.

SoCalGas’ average cost of natural gas for the three months ended March 31, 2016 was $2.57 per Mcf compared to $3.10 per Mcf for the corresponding period in 2015, a 17-percent decrease of $0.53 per Mcf, resulting in lower revenues and cost of $52 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 costs 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 accounting principles generally accepted in the United States of America (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.

The table below summarizes natural gas and electric revenue for our utilities outside of California:

OTHER UTILITIES
NATURAL GAS AND ELECTRIC REVENUES
(Dollars in millions)
	Three months ended March 31, 2016			Three months ended March 31, 2015
	Volumes	Revenue		Volumes	Revenue
Natural Gas Sales (billion cubic feet):
Sempra Mexico – Ecogas	8	$	22	7	$	25
Sempra Natural Gas:
Mobile Gas (including transportation)	13		32	13		34
Willmut Gas	1		6	1		8
Total	22	$	60	21	$	67
Electric Sales (million kilowatt hours):
Sempra South American Utilities:
Luz del Sur	1,949	$	232	1,923	$	217
Chilquinta Energía	799		135	792		137
	2,748		367	2,715		354
Other service revenues			11			9
Total		$	378		$	363

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

Energy-Related Businesses: Revenues and Cost of Sales

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

ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
		Three months ended March 31,
		2016		2015
REVENUES
Sempra South American Utilities		$	22	$	26
Sempra Mexico			116		138
Sempra Renewables			7		8
Sempra Natural Gas			92		155
Intersegment revenues, eliminations and adjustments(1)			(57)		(67)
Total revenues		$	180	$	260
COST OF SALES(2)
Cost of natural gas, electric fuel and purchased power:
Sempra South American Utilities		$	4	$	9
Sempra Mexico			35		51
Sempra Natural Gas			74		105
Eliminations and adjustments(1)			(57)		(67)
Total		$	56	$	98
Other cost of sales:
Sempra South American Utilities		$	15	$	11
Sempra Mexico			2		5
Sempra Natural Gas			20		20
Eliminations and adjustments(1)			(2)		(1)
Total		$	35	$	35
(1)	Includes eliminations of intercompany activity.
(2)	Excludes depreciation and amortization, which are shown separately on the Condensed Consolidated Statements of Operations.

During the three months ended March 31, 2016, revenues from our energy-related businesses decreased by $80 million (31%) to $180 million. The decrease included

§   $63 million decrease at Sempra Natural Gas primarily due to:

□   $27 million lower power revenues due to the sale of the remaining block of Mesquite Power in April 2015,

□   $20 million primarily from lower natural gas prices and volumes on power sold to Sempra Mexico’s Mexicali power plant, and

□   $12 million losses associated with midstream marketing activities driven by changes in natural gas prices; and

§   $22 million lower revenues at Sempra Mexico primarily due to lower power prices and volumes in its power business, including $15 million decrease at the Mexicali power plant, and lower natural gas prices in its gas business; offset by

§   $10 million primarily from lower intercompany eliminations associated with sales between Sempra Natural Gas and Sempra Mexico.

During the three months ended March 31, 2016, the cost of natural gas, electric fuel and purchased power for our energy-related businesses decreased by $42 million (43%) to $56 million primarily due to:

§   $31 million decrease at Sempra Natural Gas primarily due to lower natural gas costs and volumes and lower electric fuel costs due to the sale of the remaining block of Mesquite Power in April 2015; and

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

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

Operation and Maintenance

Sempra Energy Consolidated

For the three months ended March 31, 2016, our operation and maintenance expenses increased by $43 million (7%) to $701 million, primarily attributable to SDG&E and SoCalGas, as we discuss below.

SDG&E

For the three months ended March 31, 2016, SDG&E’s operation and maintenance expenses increased by $29 million (13%) to $246 million primarily due to:

§   $18 million higher expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses); and

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

SoCalGas

For the three months ended March 31, 2016, SoCalGas’ operation and maintenance expenses increased by $13 million (4%) to $327 million primarily due to:

§   $17 million higher non-refundable operating costs, including labor, contract services and administrative and support costs; offset by

§   $5 million lower expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses).

Plant Closure Adjustment

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

Equity (Losses) Earnings, Before Income Tax

Equity losses, before income tax, for the three months ended March 31, 2016 were $22 million compared to equity earnings, before income tax, of $19 million for the same period in 2015. The change was primarily due to a $44 million ($27 million after-tax) impairment charge related to Sempra Natural Gas’ investment in Rockies Express, which we discuss 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 and effective income tax rates for Sempra Energy, SDG&E and SoCalGas.

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
			Effective				Effective
		Income tax	income			Income tax	income
		expense	tax rate			expense	tax rate
		Three months ended March 31,
		2016				2015
Sempra Energy Consolidated	$	142	31	%	$	163	27	%
SDG&E		72	36			88	37
SoCalGas		87	31			95	31

Sempra Energy Consolidated

The decrease in income tax expense in the three months ended March 31, 2016 was due to lower pretax income, offset by a higher effective income tax rate, primarily due to:

§   $29 million deferred Mexican income tax expense on our outside basis difference in Termoeléctrica de Mexicali as a result of management’s decision to hold the asset for sale. We discuss the planned sale further in Note 3 of the Notes to Condensed Consolidated Financial Statements herein; offset by

§   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. 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.

SDG&E

The decrease in SDG&E’s income tax expense in the three months ended March 31, 2016 was primarily due to lower pretax income.

SoCalGas

The decrease in SoCalGas’ income tax expense in the three months ended March 31, 2016 was due to lower pretax income.

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.

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)
		First quarter 2016 compared to first quarter 2015
Lower earnings from foreign currency translation:
Sempra South American Utilities	$	5
Sempra Mexico		1
Total	$	6

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:

TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION
(Dollars in millions)
					Transactional
					gains (losses) included
	Total reported amount				in reported amounts
	Three months ended March 31,
	2016		2015		2016		2015
Other income, net	$	49	$	39	$	1	$	(1)
Income tax expense		142		163		1		6
Equity earnings, net of income tax		17		15		1		1
Earnings		319		437		3		5

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 (Gasoductos de Chihuahua, or GdC, and Energía Sierra Juárez) 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.

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 joint venture projects (Los Ramones I and Los Ramones Norte) 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 Equity Earnings, Net of Income Tax. The activity of foreign currency forwards and swaps related to these contracts settle through Equity Earnings, Net of Income Tax.

Our South American joint ventures (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, distributions from our equity method investments and project financing.

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 20 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 March 31, 2016. Our foreign operations have additional general purpose credit facilities, aggregating $1.1 billion at March 31, 2016. Available unused credit on these lines totaled $876 million at March 31, 2016.

AVAILABLE FUNDS AT MARCH 31, 2016
(Dollars in millions)
		Sempra Energy
		Consolidated		SDG&E		SoCalGas
Unrestricted cash and cash equivalents(1)		$	376	$	36	$	14
Available unused credit(2)			3,160		584		745
(1)	Amounts at Sempra Energy Consolidated include $311 million held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated, as we discuss below.
(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 March 31, 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. SDG&E's and SoCalGas' available funds reflect commercial paper outstanding of $166 million and $5 million, respectively, supported by the line.

Sempra Energy Consolidated

We believe thatthese available funds, combined with cash flows from operations, distributions from equity method investments, proceeds ofsecurities 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

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 at Sempra International and Sempra U.S. Gas & Power. If cash flows from operations were to be significantly reduced or we were unable to borrow under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety) and investments in new businesses. If these measures were necessary, they would primarily impact 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.

In addition to capital expenditures, the net decrease in Sempra Energy Consolidated cash and cash equivalents at March 31, 2016 compared to December 31, 2015 of $27 million was primarily due to expenditures at SoCalGas related to the natural gas leak at the Aliso Canyon facility and common dividends paid, partially offset by commercial paper borrowings on the Sempra Global credit facility. 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.

At March 31, 2016, our cash and cash equivalents held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated are $311 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 three 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 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 as approved by the CPUC in the most recent cost of capital proceeding, 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 April 28, 2016, 138 lawsuits have been filed against SoCalGas, some of which have also named Sempra Energy, and in derivative and securities law claims on behalf of Sempra Energy and/or SoCalGas, certain officers and directors of Sempra Energy and/or SoCalGas. In addition, the Los Angeles City Attorney and Los Angeles County Counsel have also filed a complaint on behalf of the people of the State of California against SoCalGas for public nuisance and violation of the California Unfair Competition Law. 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), joined that existing lawsuit. The complaint, which as amended includes the California Attorney General, adds allegations of violations of certain California Health and Safety Code and California Government Code sections. The South Coast Air Quality Management District (SCAQMD) also 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. On February 2, 2016, the Los Angeles 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 violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public. 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, 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.

In connection with the temporary relocation support, on April 27, 2016, the California Superior Court (Superior Court) ordered an extension of the relocation support term pending the completion of the County of Los Angeles’ (County) indoor testing. The County has reported that it anticipates completing its analysis and releasing a final report by late May 2016. The next scheduled Superior Court hearing on this matter is June 7, 2016. While the temporary relocation support period could end before June 7, 2016, due to the fact that the temporary relocation support has been extended several times, there can be no assurance that future extensions will not be granted. The cost of the temporary relocation support is significant, and the costs of any further extensions of the relocation support term, which are not included in our estimate of costs related to the leak, could result in a material increase in our cost estimate.

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.

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.

SDG&E notified bondholders in April 2016 that it intends to redeem, prior to maturity, certain outstanding long-term debt instruments with a total principal amount of $105 million. The debt is classified as long-term at March 31, 2016 on Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets. The coupon rate of these instruments is 5 percent and they mature in 2027. SDG&E expects to redeem the debt in the second quarter of 2016.

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 and the amount billed to customers in rates. In December 2015, the CPUC approved SDG&E’s 2016 ERRA revenue requirement of $1.3 billion, an increase of $43 million from its 2015 revenue requirement. As the new revenue requirement was effective on January 1, 2016, management expects the ERRA balance to remain stable in 2016. SDG&E’s ERRA balance was undercollected by $38 million at March 31, 2016 and overcollected by $25 million at December 31, 2015. We discuss the revenue requirement for ERRA further in Note 14 of the Notes to Consolidated Financial Statements and other 2015 impacts on ERRA balances in “Capital Resources and Liquidity – Overview – California Utilities” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” both in the Annual Report.

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 the core market, and the actual revenues billed to customers in rates for recovery of these costs. Because warmer weather experienced in 2014 and 2015 resulted in lower natural gas consumption compared to authorized levels, SoCalGas’ CFCA balance was undercollected by $313 million at March 31, 2016 and $328 million at December 31, 2015. SDG&E’s CFCA balance was undercollected by $76 million at March 31, 2016 and $105 million at December 31, 2015.

Under its current ratemaking treatment, SoCalGas and SDG&E have the authority through an Annual Regulatory Account Balance Update filing to recover undercollections accumulated in the prior year, consisting of actual recorded activity through August and an estimate for the remainder of the year. SoCalGas and SDG&E are currently amortizing $417 million and $99 million, respectively, of the December 31, 2015 CFCA balance in 2016 rates.

Sempra South American Utilities

We expect projects and loans to affiliates at Chilquinta Energía and Luz del Sur to be funded by available funds, funds internally generated by those businesses and by external borrowings. At March 31, 2016 and December 31, 2015, Sempra South American Utilities had outstanding loans of $76 million and $72 million, respectively, to an affiliate to finance development projects. We discuss these transactions in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Mexico

We expect projects, joint venture investments and dividends in Mexico to be funded through a combination of available funds, including credit facilities, funds internally generated by the Mexico businesses, securities issuances, project financing, interim funding from the parent, and partnering in joint ventures. In 2015 and 2014, Sempra Mexico paid dividends of $32 million and $31 million, respectively, to its minority shareholders.

We discuss IEnova’s potential acquisition of Petróleos Mexicanos’ (or PEMEX, the Mexican state-owned oil company) 50-percent interest in GdC in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

At March 31, 2016 and December 31, 2015, Sempra Mexico had outstanding loans of $104 million and $111 million, respectively, to affiliates to finance development projects. We discuss these transactions in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Mexico may also generate cash from the sale of its 625-megawatt (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 book value of $260 million at March 31, 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. The Sempra Renewables projects have planned in-service dates through 2016.

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. Sempra Natural Gas also expects to receive approximately $440 million in proceeds from the pending sale of its investment in Rockies Express, and approximately $323 million from the pending sale of Mobile Gas and Willmut Gas, as we discuss is Notes 3 and 13, respectively, of the Notes to Condensed Consolidated Financial Statements herein. Proceeds from both transactions are subject to adjustment at closing. 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 in the second half of 2019.

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.

CASH FLOWS FROM OPERATING ACTIVITIES

CASH PROVIDED BY OPERATING ACTIVITIES
(Dollars in millions)
	Three months ended March 31, 2016		2016 change				Three months ended March 31, 2015
Sempra Energy Consolidated	$	592	$	(219)	(27)	%	$	811
SDG&E		369		70	23			299
SoCalGas		241		(134)	(36)			375

Sempra Energy Consolidated

Cash provided by operating activities at Sempra Energy decreased in 2016 primarily due to:

§   $335 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 $28 million net increase in reserve for accrued expenditures related to the leak. The $28 million net increase includes $335 million of additional accruals, offset by $307 million of cash expenditures;

§   $40 million decrease in inventories in 2016 compared to a $132 million decrease in 2015, primarily due to lower gas inventory at SoCalGas as a result of the current moratorium on natural gas injections at its Aliso Canyon natural gas storage facility;

§   $40 million lower net income, adjusted for noncash items included in earnings, in 2016 compared to 2015; and

§   $28 million higher decrease in compensation and benefit accruals in 2016 compared to 2015; offset by

§   $7 million increase in accounts payable in 2016 compared to a $152 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;

§   $189 million decrease in accounts receivable in 2016 compared to a $129 million decrease in 2015, primarily due to lower natural gas prices at SoCalGas in 2016; and

§   $84 million net decrease in net undercollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2016 at the California Utilities compared to a $27 million net decrease in 2015. Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time. See further discussion of changes in regulatory balances at both SDG&E and SoCalGas below.

SDG&E

Cash provided by operating activities at SDG&E increased in 2016 primarily due to:

§   $26 million decrease in accounts receivable in 2016 compared to a $15 million increase in 2015;

§   $27 million increase in greenhouse gas allowances in 2016 compared to a $67 million increase in 2015; and

§   $8 million net income tax refunds in 2016 compared to $31 million net income tax payments in 2015; offset by

§   $30 million lower net income, adjusted for noncash items included in earnings, in 2016 compared to 2015.

SoCalGas

Cash provided by operating activities at SoCalGas decreased in 2016 primarily due to:

§   $335 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 $28 million net increase in reserve for accrued expenditures related to the leak. The $28 million net increase includes $335 million of additional accruals, offset by $307 million of cash expenditures;

§   $23 million increase in income taxes payable in 2016 compared to a $107 million increase in 2015; and

§   $46 million decrease in inventories in 2016 compared to a $72 million decrease in 2015, primarily due to lower gas inventory as a result of the current moratorium on natural gas injections at the Aliso Canyon storage facility; offset by

§   $29 million decrease in accounts payable in 2016 compared to a $160 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;

§   $20 million increase in net overcollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2016 compared to a $49 million increase in net undercollected balances in 2015, primarily due to changes in fixed cost balancing accounts;

§   $57 million higher net income, adjusted for noncash items included in earnings, in 2016 compared to 2015; and

§   $186 million decrease in accounts receivable in 2016 compared to a $136 million decrease in 2015, primarily due to lower natural gas prices in 2016.

The table below shows the contributions to pension and other postretirement benefit plans.

CONTRIBUTIONS TO PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
	Three months ended March 31, 2016
			Other
	Pension		postretirement
	benefits		benefits
Sempra Energy Consolidated	$	15	$	1
SDG&E		2		―

CASH FLOWS FROM INVESTING ACTIVITIES

CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
	Three months ended						Three months ended
	March 31, 2016		2016 change				March 31, 2015
Sempra Energy Consolidated	$	(989)	$	219	28	%	$	(770)
SDG&E		(330)		(91)	(22)			(421)
SoCalGas		(290)		(99)	(25)			(389)

Sempra Energy Consolidated

Cash used in investing activities at Sempra Energy increased in 2016 primarily due to:

§   $191 million increase in capital expenditures; and

§   $24 million lower repayments of advances to unconsolidated affiliates.

SDG&E

Cash used in investing activities at SDG&E decreased in 2016 due to:

§   $66 million advances to Sempra Energy in 2015; and

§   $26 million decrease in capital expenditures in 2016.

SoCalGas

Cash used in investing activities at SoCalGas decreased in 2016 due to:

§   $50 million decrease in advances to Sempra Energy in 2016 compared to a $74 million increase in 2015; offset by

§   $25 million increase in capital expenditures in 2016.

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 $5.5 billion. These expenditures include

§   $2.7 billion at the California Utilities for capital projects and plant improvements ($1.3 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

§   $2.8 billion at our other subsidiaries for acquisition of our joint venture partner’s 50-percent interest in GdC, 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

§   $800 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 $350 million for the PSEP

§   $100 million for advanced metering infrastructure

§   $100 million for other natural gas projects

The California Utilities expect to finance these expenditures and investments with cash flows from operations and debt issuances.

In 2016, the expected capital expenditures and investments of approximately $2.8 billion at our other subsidiaries include

Sempra South American Utilities

§   approximately $220 million for capital projects in South America (approximately $160 million and $60 million in Peru and Chile, respectively), primarily related to improvements to electric transmission and distribution systems

Sempra Mexico

§   approximately $450 million to $500 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

§   funds for the potential acquisition of our joint venture partner’s 50-percent interest in GdC, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein

Sempra Renewables

§   approximately $900 million for the development of wind and solar renewable projects, including Black Oak Getty Wind, Mesquite Solar 2, Mesquite Solar 3 and Copper Mountain Solar 4

Sempra Natural Gas

§   approximately $170 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 $80 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 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)
	Three months ended				Three months ended
	March 31, 2016		2016 change		March 31, 2015
Sempra Energy Consolidated	$	364	$	595	$	(231)
SDG&E		(23)		(160)		137
SoCalGas		5		55		(50)

Sempra Energy Consolidated

At Sempra Energy, financing activities were a net source of cash in 2016 compared to a net use of cash in 2015, primarily due to:

§   $531 million increase in short-term debt in 2016 compared to a $363 million decrease in 2015; and

§   $600 million lower payments on debt, including lower payments of long-term debt of $8 million ($22 million in 2016 compared to $30 million in 2015), and lower payments of commercial paper and other short-term debt with maturities greater than 90 days of $592 million ($32 million in 2016 compared to $624 million in 2015); offset by

§   $883 million lower issuances of debt, primarily from issuances of long-term debt in 2015.

SDG&E

At SDG&E, financing activities were a net use of cash in 2016 compared to a net source of cash in 2015, primarily due to:

§   $388 million net proceeds from issuances of long-term debt in 2015; and

§   $17 million higher payments on long-term debt in 2016; offset by

§   $2 million decrease in short-term debt in 2016 compared to a $246 million decrease in 2015.

SoCalGas

At SoCalGas, financing activities were a net source of cash in 2016 compared to a net use of cash in 2015 due to a $5 million increase in short-term debt in 2016 compared to a $50 million decrease 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 three 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.

Joint Matters

CPUC General Rate Case (GRC)

As we discuss further in Note 10 of the Notes to Condensed Consolidated Financial Statements herein, in September 2015, the California Utilities filed settlement agreements with the CPUC that resolve all material matters related to their 2016 GRC proceeding, except for the revenue requirement implications of certain income tax benefits associated with flow-through repair allowance tax deductions, discussed below. The California Utilities also filed a separate agreement, reached with the CPUC Office of Ratepayer Advocates (ORA), proposing that a fourth year (2019) be added to the GRC period, with a revenue requirement increase of 4.3 percent over 2018. On April 29, 2016, the CPUC issued a proposed decision in a separate proceeding denying the potential of four-year GRC cycles citing that an extension to the GRC period would delay the implementation of the risk-based decision making framework.

The settlement agreements noted above exclude a proposal, for both SoCalGas and SDG&E, regarding certain intra-rate case income tax benefits. The proposal recommends that the CPUC adjust SoCalGas’ rate base by $92 million and SDG&E’s rate base by $93 million, and additionally reduce both utilities’ revenue requirements by amounts tracked in tax memorandum accounts for the year 2015, which total $74 million for SoCalGas and $39 million for SDG&E. We believe the proposed treatment would violate and contradict long standing rate making and income tax policy, and would represent a material departure from historical practice. If this proposal is adopted, the outcome would reduce the revenue requirement amounts agreed to in the respective settlement agreements noted above. SDG&E and SoCalGas do not expect that the prospective reduction to rate base described above would result in an immediate earnings impact if this proposal is adopted. However, if this proposal is adopted, SDG&E and SoCalGas may record a material charge against earnings for the amounts in the tax memorandum accounts when the proposed decision is received.

We anticipate all matters to be resolved in the CPUC’s final decision on the 2016 GRC proceeding. We expect the CPUC to issue a final decision in the proceeding in the second quarter of 2016.

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 concluded in 2013. Similarly, these costs are not included in our 2016 GRC filings.

In June 2014, the CPUC issued a final decision addressing SDG&E’s and SoCalGas’ Pipeline Safety Enhancement Plan (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 March 31, 2016, SDG&E and SoCalGas have recorded PSEP costs of $12 million and $177 million, respectively, in the CPUC-authorized regulatory account.

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 in the subsequent year. This request is pending at the CPUC. SDG&E and SoCalGas have filed with the CPUC for recovery of certain PSEP costs incurred through June 11, 2014 of $0.1 million and $26.8 million, respectively. The ORA, The Utility Reform Network (TURN), and the Southern California Generation Coalition (SCGC) have recommended disallowances of certain of these costs. We expect a decision on this application in the first half of 2016.

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. Through March 31, 2016, the after-tax disallowed costs for SoCalGas and SDG&E are $2.6 million and $0.5 million, respectively. In January 2016, SoCalGas and SDG&E jointly filed a request with the CPUC seeking rehearing of its December 2015 decision. A CPUC decision on the rehearing request is expected in 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. The CPUC plans to make further refinements to the electric and gas safety enforcement programs.

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 March 31, 2016, Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets include assets of $363 million in Other Regulatory Assets (long-term), of which $360 million is related to CPUC-regulated operations and $3 million is related 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, a ruling was issued 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. 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 March 31, 2016, the resulting after-tax charge against earnings would have been up to approximately $213 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.

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.

Investment in Wind Farm

In 2011, the CPUC and FERC approved SDG&E’s estimated $285 million tax equity investment in the Rim Rock wind farm project. SDG&E and the project developer were in dispute regarding whether all conditions precedent in the contribution agreement had been achieved by the developer of the project. As a result, SDG&E had not made the investment. On February 11, 2016, SDG&E, the project developer and several of the project developer’s parent and affiliated entities entered into a conditional settlement agreement. Under the conditional 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. The conditional settlement agreement will not result in rate increases to SDG&E customers or a material impact on Sempra Energy’s or SDG&E’s financial condition, results of operations or cash flows. On February 16, 2016, SDG&E and the project developer filed a petition for approval of the settlement agreement with the CPUC. The conditional settlement agreement is not fully effective until approved by the CPUC; SDG&E expects a decision in 2016. We discuss this matter further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein and in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Electric Rate Reform – State of 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 ($5 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 will be reduced to two in 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 super user electric (SUE) 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 SUE 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. A CPUC decision on the rehearing requests is expected in 2016.

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.

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 GHG 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. SB 350 also enhances focus on improving efficiency in older buildings. 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.

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 and in response to claims made pursuant to lawsuits described below, 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 California Superior Court (Superior Court) ordered an extension of the relocation support term pending the completion of the County of Los Angeles’ (County) indoor testing. The County has reported that it anticipates completing its analysis and releasing a final report by late May 2016. The next scheduled Superior Court hearing on this matter is June 7, 2016. While the temporary relocation support period could end before June 7, 2016, due to the fact that the temporary relocation support has been extended several times, there can be no assurance that future extensions will not be granted. The cost of the temporary relocation support is significant, and the costs of any further extensions of the relocation support term, which are not included in our estimate of costs related to the leak, could result in a material increase in our cost estimate.

The total costs incurred to remediate and stop the leak and to mitigate local community impacts will be significant, and to the extent not covered by insurance, 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.

Various governmental agencies including the DOGGR, Los Angeles County Department of Public Health, SCAQMD, 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 District Attorney’s Office, and California Attorney General’s Office, are investigating this incident.

As of April 28, 2016, 138 lawsuits have been filed (134 in Los Angeles County Superior Court, 2 in San Diego County Superior Court, and 2 in the United States District Court for the Southern District of California) against SoCalGas, some of which have also named Sempra Energy, and, in derivative and securities law claims on behalf of Sempra Energy and/or SoCalGas, certain officers and directors of Sempra Energy and/or SoCalGas. These various lawsuits assert causes of action for negligence, strict liability, property damage, fraud, nuisance, trespass, breach of fiduciary duties and violation of federal securities laws, among other things, and additional litigation may be filed against us in the future related to this incident. Many of these complaints seek class action status, compensatory and punitive damages, injunctive relief and attorneys’ fees. The Los Angeles City Attorney and Los Angeles County Counsel have also filed a complaint on behalf of the people of the State of California against SoCalGas for public nuisance and violation of the California Unfair Competition Law. The California Attorney General, acting in her independent capacity and on behalf of the people of the State of California and the CARB, joined this lawsuit. The complaint, which as amended includes the California Attorney General, adds allegations of 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 also 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 February 2, 2016, the Los Angeles 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 violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public.

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, could be significant and to the extent not covered by insurance, 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, control the release of natural gas into the air, and conduct air monitoring and public health studies. We provide further detail regarding the SCAQMD’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 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 late 2016 or early 2017, but the timing is dependent on 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 April 1, 2016, the Secretary of the U.S. Department of Energy (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. PHMSA has indicated plans to initiate additional regulatory actions on natural gas storage nationally. Each of the DOGGR, SCAQMD, EPA and CARB has commenced separate rulemaking proceedings to adopt further regulations covering natural gas storage facilities and injection wells. The U.S. Senate also passed two pieces of legislation, which include a provision requiring the establishment of an Aliso Canyon Task Force. This generally mirrors the focus and structure of the Task Force on Natural Gas Storage Safety. The legislation requires the Task Force to examine a specific set of issues related to the leak, including impacts on health and electricity prices.

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.

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 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 ensuring service reliability during peak demand periods, including heating needs in the winter, as well as peak electric generation needs in the summer. Aliso Canyon, with a storage capacity of 86 billion cubic feet (Bcf), is the largest storage facility and an important element of SoCalGas’ delivery system. Aliso Canyon represents 63 percent of SoCalGas’ owned natural gas storage capacity. SoCalGas has not injected natural gas into Aliso Canyon since October 25, 2015, in accordance with the Governor’s Order and subject to contrary CPUC reliability-based direction. 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 the completion of this review and any necessary approvals have been obtained.

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 March 31, 2016, the Aliso Canyon facility has a net book value of $415 million, including $180 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.

On March 17, 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, on March 24, 2016, 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 TURN and SCGC. On April 22, 2016, the CPUC’s Energy Division issued a suspension notice for SoCalGas’ advice letter citing the need for additional time for staff review. This suspension period could last up to 120 days.

We have at least four kinds of insurance policies that provide in excess of $1 billion in insurance coverage. 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 at March 31, 2016 of $665 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, 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, the costs not included in the $665 million estimate could be material, and to the extent not covered by insurance, 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 “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 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 next rate reviews for sub-transmission are expected to be completed in the second quarter of 2016, with tariff adjustments going into effect retroactively from January 2016. The next rate reviews for distribution are scheduled to be completed, with tariff adjustments also going into effect, in November 2016. Sub-transmission will cover the period from January 2016 to December 2019 and distribution will cover the period from November 2016 to October 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.

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 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 $752 million in goodwill recorded at March 31, 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 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 $76 million outstanding at March 31, 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. Once in operation, the capitalized cost will earn the regulated return for 30 years. The project will be financed through Luz del Sur’s existing debt program in Peru’s capital markets.

Sempra Mexico

Overview

Sempra Mexico is expected to provide earnings from construction projects when completed and from joint venture investments. We expect projects, joint venture investments and dividends in Mexico to be funded through a combination of available funds, including credit facilities, 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 Termoeléctrica de Mexicali natural gas-fired power plant.

IEnova and PEMEX are 50-50 partners in the joint venture Gasoductos de Chihuahua (GdC). IEnova currently accounts for its 50-percent interest in GdC as an equity method investment. In July 2015, IEnova entered into an agreement to purchase PEMEX’s 50-percent interest in GdC, which at closing would increase its interest from 50 percent to 100 percent. As we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein, the parties are in the process of restructuring the transaction in response to issues raised in the review of the transaction by Mexico’s antitrust commission. The terms and conditions of the revised transaction are still under negotiation, and there can be no assurance that a new agreement will be reached. Any restructured transaction remains subject to satisfactory completion of the Mexican antitrust review and may require further approvals from other Mexican authorities.

The sharp decline in crude oil prices beginning in late 2014 and continuing into 2016, as well as low natural gas prices, have had a negative impact on PEMEX’s revenues, income and cash flows. Certain rating agencies have expressed several concerns regarding PEMEX’s financial condition, including the total amount of PEMEX’s debt and the significant increase in PEMEX’s indebtedness over the last several years, as well as its substantial unfunded reserve for retirement pensions and seniority premiums. 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, based on its view that the company’s current weak credit metrics will worsen as it continues to fund capital expenditures from external sources, the same major credit rating agency further downgraded PEMEX’s global foreign currency and local currency credit ratings from Baa1 to Baa3 and affirmed that the outlook on its 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 GDC 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.

In February 2016, management approved a plan to market and sell Sempra Mexico’s Termoeléctrica de Mexicali, 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 an asset held for sale, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein. We expect to complete the sale in the second half of 2016.

Pipeline Projects

In October 2012, IEnova 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 2016. 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 GdC joint venture has a 50-percent interest in the project. The pipeline began commercial operation in February 2016. We expect the two compression stations to begin operation in the second quarter of 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 an affiliate of its joint venture with PEMEX totaling $87 million outstanding at March 31, 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.

IEnova 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.

Energía Sierra Juárez

In 2014, we consummated the sale of a 50-percent equity interest in the first phase of Energía Sierra Juárez to a wholly owned subsidiary of 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 and began commercial operations in June 2015. 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 to Energía Sierra Juárez, its affiliate, totaling $17 million outstanding at March 31, 2016 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 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. In addition, this project requires 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, and reaching a final investment decision. For a discussion of these risks, 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 2016. 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.

Black Oak Getty Wind Project

In March 2015, Sempra Renewables acquired the Black Oak Getty Wind project, a 78-MW wind farm under development in Stearns County, Minnesota. Sempra Renewables is completing the development 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 development by Sempra Renewables in Boulder City, Nevada. When fully developed, 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 in 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 development by Sempra Renewables in Maricopa County, Arizona. If fully developed, the project will be capable of producing up to approximately 700 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 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

Rockies Express and Pipeline Capacity

Sempra Natural Gas owns a 25-percent interest in Rockies Express, a partnership that operates the Rockies Express natural gas pipeline (REX), which links the Rocky Mountains region to the upper Midwest and the eastern United States. Sempra Natural Gas has an agreement for certain capacity on REX through November 2019. The capacity costs have been partially offset by revenues from releases of the capacity contracted to third parties.

In March 2016, Sempra Natural Gas entered into an agreement with a subsidiary of Tallgrass Development, LP to sell Sempra Natural Gas’ 25-percent interest in Rockies Express for approximately $440 million in cash, subject to adjustment at closing. The transaction is subject to customary closing conditions. Sempra Natural Gas expects the transaction to close in the second quarter of 2016. We discuss this transaction and the investment in Rockies Express further in Notes 3 and 8 of the Notes to Condensed Consolidated Financial Statements herein.

Additionally, Sempra Natural Gas intends to permanently release uncontracted capacity that it had been releasing on an interim basis. The effect of the permanent capacity release is expected to result in a charge to earnings of approximately $100 million to $120 million during the second quarter of 2016, representing an acceleration of losses that would otherwise be realized over the contract term, which extends through November 2019.

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 below in “Cameron Liquefaction”) 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 March 31, 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.

Natural Gas Distribution Utilities

In April 2016, Sempra Natural Gas entered into a definitive agreement to sell the parent company of Mobile Gas and Willmut Gas. We expect to receive cash proceeds of approximately $323 million, subject to normal adjustments at closing, and the buyer will assume existing debt of approximately $67 million. In April 2016, we reclassified the assets and liabilities of Mobile Gas and Willmut Gas to held for sale. We expect to recognize a gain on the sale of approximately $70 million after-tax. The transaction is subject to customary regulatory approvals, and we expect the sale to close in 2016.

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 million cubic feet (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 during the first half of 2017 due to progress on the construction of the three-train liquefaction project. Sempra Natural Gas also may enter into short-term supply agreements to purchase LNG to be received, stored, and regasified at the terminal for sale to other parties.

The current liquefaction project under construction, which will utilize 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. We expect the project to achieve commercial operation of all three trains in 2018, and have the first year of full operations in 2019. The anticipated incremental investment in the three-train liquefaction 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.

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 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 in the second half of 2019.

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 would 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 where piping tie-ins to the existing regasification terminal become necessary. Based on the full notice to proceed that was issued to Cameron LNG JV’s EPC contractor in October 2014, we expect this termination date to occur during the first half of 2017.

In December 2014, Cameron LNG JV filed with the U.S. Department of Energy (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 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 the two additional trains and the one containment 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. On February 12, 2016, Cameron LNG JV received the FERC environmental assessment, and expects to receive the FERC permit in the second quarter of 2016.

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 consent of all the partners, including with respect to the equity investment obligation of each partner. Recently, one of the partners indicated to Sempra Energy that although it plans to consent to the expansion, it currently does not plan to invest additional equity in the expansion. Under those circumstances, the proposed amendment of the Cameron LNG JV agreement would allocate the equity investment obligations for the expansion to one or more of the other partners.

The expansion of the Cameron LNG JV facilities beyond the first three trains is subject to a number of risks and uncertainties, including completing the required commercial agreements, amending the Cameron LNG JV agreement among the partners, securing all necessary permits and approvals, 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 an interest in long-term contracts for LNG supplies beginning in the 2020 to 2023 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 three months ended March 31, 2016 were $14 million, including capitalized costs of $8 million (pretax). After-tax LNG development costs expensed for the three months ended March 31, 2016 were $4 million. We expect to expense approximately $20 million to $25 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 March 31, 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.

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 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.

We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We follow the same accounting policies for interim reporting purposes.

NEW ACCOUNTING STANDARDS

We discuss the relevant pronouncements that have recently become effective and have had or may have an impact on our financial statements and/or disclosures in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We provide disclosure regarding derivative activity in Note 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" in the Annual Report, and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.

INTEREST RATE RISK

The table below shows the nominal amount of long-term debt at March 31, 2016 and December 31, 2015:

NOMINAL AMOUNT OF LONG-TERM DEBT(1)
(Dollars in millions)
		March 31, 2016						December 31, 2015
		Sempra Energy						Sempra Energy
		Consolidated		SDG&E		SoCalGas		Consolidated		SDG&E		SoCalGas
Utility fixed-rate		$	6,344	$	3,832	$	2,512	$	6,362	$	3,849	$	2,513
Utility variable-rate			452		452		―		455		455		―
Non-utility fixed-rate			6,801		―		―		6,780		―		―
Non-utility variable-rate			166		―		―		166		―		―
(1)	Excluding capital lease obligations, build-to-suit lease and interest rate swaps, and before reductions/increases for unamortized discount/premium and reductions for debt issuance costs.

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 one percent on all of Sempra Energy’s effective variable-rate, long-term debt at March 31, 2016, the change in earnings over the next 12-month period ending March 31, 2017 would be $5 million (after-tax), including $3 million (after-tax) 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. At March 31, 2016, there were no significant changes to our exposure to foreign currency rate risk since December 31, 2015. If IEnova’s potential acquisition of the remaining 50-percent interest in GdC is completed, Sempra Mexico will be subject to additional foreign currency rate risk. 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 March 31, 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

There have been no changes in the companies’ internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the companies’ internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses) except for the matters 1) described in Notes 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 10 -- MATERIAL CONTRACTS
Compensation
Sempra Energy / San Diego Gas & Electric Company / Southern California Gas Company
10.1	Form of Indemnification Agreement with Directors and Executive Officers (executed
	after January 2011).
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.
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

SIGNATURES
Sempra Energy:
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
	SEMPRA ENERGY, (Registrant)
Date: May 4, 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)
Date: May 4, 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)
Date: May 4, 2016	By:  /s/ Bruce A. Folkmann
	Bruce A. Folkmann Vice President, Controller, Chief Financial Officer and Chief Accounting Officer