Edgar Filing: SEMPRA ENERGY

Sempra Energy/SDG&E/SoCalGas September 30, 2015 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

[X]

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

For the quarterly period ended

September 30, 2015

[ ]

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

For the transition period from

Commission File No.

Exact Name of Registrants as Specified in their Charters, Address and Telephone Number

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

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

San Diego Gas & Electric Company

Yes

Southern California Gas Company

Yes

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

San Diego Gas & Electric Company

Yes

Southern California Gas Company

Yes

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.

Common stock outstanding on October 28, 2015:

Sempra Energy

248,210,449 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	82
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	126
Item 4.	Controls and Procedures	127

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	128
Item 1A.	Risk Factors	128
Item 6.	Exhibits	128

Signatures		130

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,” “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 and regulatory conditions and developments;

actions and the timing of actions, including issuances of permits to construct and licenses for operation, by the California Public Utilities Commission, California State Legislature, U.S. Department of Energy, Federal Energy Regulatory Commission, Nuclear Regulatory Commission, Atomic Safety and Licensing Board, California Energy Commission, U.S. Environmental Protection Agency, California Air Resources Board, 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;

§	energy markets, including the timing and extent of changes and volatility in commodity prices, and the impact of any protracted reduction in oil and natural gas prices from historical averages;

§	the impact on the value of our natural gas storage assets 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;

§	delays in the timing of costs incurred and the timing of the regulatory agency authorization to recover such costs in rates from customers;

§	deviations from regulatory precedent or practice that result in a reallocation of benefits or burdens among shareholders and ratepayers;

§	capital markets conditions, including the availability of credit and the liquidity of our investments;

§	inflation, interest and currency exchange rates;

§	the impact of benchmark interest rates, generally Moody’s A-rated utility bond yields, on our California Utilities’ cost of capital;

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, pipeline explosions and equipment failures and the decommissioning of San Onofre Nuclear Generating Station (SONGS);

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, 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, conservation efforts, natural disasters, catastrophic accidents, and other events that may disrupt our operations, damage our facilities and systems, and subject us to third-party liability for property damage or personal injuries;

§	risks that our partners or counterparties will be unable or unwilling to fulfill their contractual commitments;

§	risks posed by decisions and actions of third parties who control the operations of investments in which we do not have a controlling interest;

risks inherent with nuclear power facilities and radioactive materials storage, including the catastrophic release of such materials, the disallowance of the recovery of the investment in, or operating costs of, the nuclear facility due to an extended outage and facility closure, and increased regulatory oversight, including motions to modify settlements;

§	business, regulatory, environmental and legal decisions and requirements;

§	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;

§	the resolution of litigation; 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 filed 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				Nine months ended
	September 30,				September 30,
	2015		2014		2015		2014
	(unaudited)
REVENUES
Utilities	$	2,213	$	2,463	$	6,768	$	7,318
Energy-related businesses		268		352		762		970
Total revenues		2,481		2,815		7,530		8,288
EXPENSES AND OTHER INCOME
Utilities:
Cost of natural gas		(201)		(293)		(786)		(1,308)
Cost of electric fuel and purchased power		(666)		(680)		(1,645)		(1,761)
Energy-related businesses:
Cost of natural gas, electric fuel and purchased power		(91)		(163)		(262)		(427)
Other cost of sales		(34)		(42)		(111)		(122)
Operation and maintenance		(701)		(726)		(2,072)		(2,131)
Depreciation and amortization		(315)		(292)		(925)		(866)
Franchise fees and other taxes		(111)		(104)		(314)		(301)
Plant closure adjustment		―		―		21		13
Gain on sale of equity interests and assets		―		19		62		48
Equity earnings, before income tax		33		22		79		62
Other income, net		12		29		88		118
Interest income		6		6		23		15
Interest expense		(143)		(144)		(416)		(418)
Income before income taxes and equity earnings
of certain unconsolidated subsidiaries		270		447		1,272		1,210
Income tax expense		(15)		(71)		(276)		(291)
Equity earnings, net of income tax		27		7		64		22
Net income		282		383		1,060		941
Earnings attributable to noncontrolling interests		(34)		(35)		(79)		(76)
Preferred dividends of subsidiary		―		―		(1)		(1)
Earnings	$	248	$	348	$	980	$	864

Basic earnings per common share	$	1.00	$	1.41	$	3.95	$	3.52

Weighted-average number of shares outstanding,
basic (thousands)		248,432		246,137		248,090		245,703

Diluted earnings per common share	$	0.99	$	1.39	$	3.91	$	3.45

Weighted-average number of shares outstanding,
diluted (thousands)		251,024		250,771		250,665		250,278

Dividends declared per share of common stock	$	0.70	$	0.66	$	2.10	$	1.98
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
	Sempra Energy shareholders' equity
	Pretax		Income tax		Net-of-tax		Noncontrolling
	amount		(expense) benefit		amount		interests (after-tax)		Total
	Three months ended September 30, 2015 and 2014
	(unaudited)
2015:
Net income	$	263	$	(15)	$	248	$	34	$	282
Other comprehensive income (loss):
Foreign currency translation adjustments		(92)		―		(92)		(8)		(100)
Pension and other postretirement benefits		7		(2)		5		―		5
Financial instruments		(128)		50		(78)		(3)		(81)
Total other comprehensive loss		(213)		48		(165)		(11)		(176)
Comprehensive income	$	50	$	33	$	83	$	23	$	106
2014:
Net income	$	419	$	(71)	$	348	$	35	$	383
Other comprehensive income (loss):
Foreign currency translation adjustments		(100)		―		(100)		(11)		(111)
Pension and other postretirement benefits		8		(3)		5		―		5
Financial instruments		(4)		1		(3)		3		―
Total other comprehensive loss		(96)		(2)		(98)		(8)		(106)
Comprehensive income	$	323	$	(73)	$	250	$	27	$	277

	Nine months ended September 30, 2015 and 2014
	(unaudited)
2015:
Net income	$	1,257	$	(276)	$	981	$	79	$	1,060
Other comprehensive income (loss):
Foreign currency translation adjustments		(197)		―		(197)		(21)		(218)
Pension and other postretirement benefits		11		(4)		7		―		7
Financial instruments		(122)		48		(74)		(2)		(76)
Total other comprehensive loss		(308)		44		(264)		(23)		(287)
Comprehensive income		949		(232)		717		56		773
Preferred dividends of subsidiary		(1)		―		(1)		―		(1)
Comprehensive income, after preferred
dividends of subsidiary	$	948	$	(232)	$	716	$	56	$	772
2014:
Net income	$	1,156	$	(291)	$	865	$	76	$	941
Other comprehensive income (loss):
Foreign currency translation adjustments		(141)		―		(141)		(12)		(153)
Pension and other postretirement benefits		21		(8)		13		―		13
Financial instruments		(24)		9		(15)		2		(13)
Total other comprehensive loss		(144)		1		(143)		(10)		(153)
Comprehensive income		1,012		(290)		722		66		788
Preferred dividends of subsidiary		(1)		―		(1)		―		(1)
Comprehensive income, after preferred
dividends of subsidiary	$	1,011	$	(290)	$	721	$	66	$	787
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30,		December 31,
		2015		2014(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	697	$	570
Restricted cash			13		11
Trade accounts receivable, net			1,024		1,242
Other accounts and notes receivable, net			176		152
Due from unconsolidated affiliates			3		38
Income taxes receivable			22		45
Deferred income taxes			198		305
Inventories			416		396
Regulatory balancing accounts – undercollected			585		746
Fixed-price contracts and other derivatives			66		93
Asset held for sale, power plant			―		293
Other			406		293
Total current assets			3,606		4,184

Investments and other assets:
Restricted cash			40		29
Due from unconsolidated affiliates			175		188
Regulatory assets			3,112		3,031
Nuclear decommissioning trusts			1,060		1,131
Investments			2,845		2,848
Goodwill			847		931
Other intangible assets			407		415
Dedicated assets in support of certain benefit plans			459		512
Sundry			701		561
Total investments and other assets			9,646		9,646

Property, plant and equipment:
Property, plant and equipment			37,280		35,407
Less accumulated depreciation and amortization			(9,966)		(9,505)
Property, plant and equipment, net ($390 and $410 at September 30, 2015 and December 31, 2014, respectively, related to VIE)			27,314		25,902
Total assets		$	40,566	$	39,732
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
		September 30,		December 31,
		2015		2014(1)
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt		$	1,097	$	1,733
Accounts payable – trade			1,091		1,198
Accounts payable – other			143		155
Due to unconsolidated affiliate			―		2
Dividends and interest payable			343		282
Accrued compensation and benefits			356		373
Current portion of long-term debt			1,168		469
Fixed-price contracts and other derivatives			73		55
Customer deposits			152		153
Other			695		649
Total current liabilities			5,118		5,069
Long-term debt ($307 and $315 at September 30, 2015 and December 31, 2014, respectively, related to VIE)			12,527		12,167

Deferred credits and other liabilities:
Customer advances for construction			145		144
Pension and other postretirement benefit plan obligations, net of plan assets			1,114		1,064
Deferred income taxes			3,057		3,003
Deferred investment tax credits			34		37
Regulatory liabilities arising from removal obligations			2,715		2,741
Asset retirement obligations			2,068		2,048
Fixed-price contracts and other derivatives			300		255
Deferred credits and other			1,092		1,104
Total deferred credits and other liabilities			10,525		10,396

Commitments and contingencies (Note 11)

Equity:
Preferred stock (50 million shares authorized; none issued)			―		―
Common stock (750 million shares authorized; 248 million and 246 million shares
outstanding at September 30, 2015 and December 31, 2014, respectively; no par value)			2,587		2,484
Retained earnings			9,799		9,339
Accumulated other comprehensive income (loss)			(761)		(497)
Total Sempra Energy shareholders’ equity			11,625		11,326
Preferred stock of subsidiary			20		20
Other noncontrolling interests			751		754
Total equity			12,396		12,100
Total liabilities and equity		$	40,566	$	39,732
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Nine months ended September 30,
	2015		2014
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,060	$	941
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		925		866
Deferred income taxes and investment tax credits		179		131
Gain on sale of equity interests and assets		(62)		(48)
Plant closure adjustment		(21)		(13)
Equity earnings		(143)		(84)
Fixed-price contracts and other derivatives		(20)		(19)
Other		28		32
Net change in other working capital components		260		(215)
Changes in other assets		(112)		28
Changes in other liabilities		(5)		42
Net cash provided by operating activities		2,089		1,661

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(2,227)		(2,320)
Expenditures for investments and acquisition of business		(183)		(192)
Proceeds from sale of equity interests and assets, net of cash sold		347		92
Distributions from investments		14		15
Purchases of nuclear decommissioning and other trust assets		(407)		(505)
Proceeds from sales by nuclear decommissioning and other trusts		431		498
Decrease in restricted cash		68		156
Increase in restricted cash		(81)		(139)
Advances to unconsolidated affiliates		(24)		(100)
Repayments of advances to unconsolidated affiliates		74		19
Other		9		10
Net cash used in investing activities		(1,979)		(2,466)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(468)		(450)
Preferred dividends paid by subsidiary		(1)		(1)
Issuances of common stock		41		43
Repurchases of common stock		(74)		(38)
Issuances of debt (maturities greater than 90 days)		2,058		3,063
Payments on debt (maturities greater than 90 days)		(1,316)		(1,845)
Decrease in short-term debt, net		(201)		(111)
Net distributions to noncontrolling interests		(57)		(84)
Other		47		(5)
Net cash provided by financing activities		29		572

Effect of exchange rate changes on cash and cash equivalents		(12)		(4)

Increase (decrease) in cash and cash equivalents		127		(237)
Cash and cash equivalents, January 1		570		904
Cash and cash equivalents, September 30	$	697	$	667
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
	Nine months ended September 30,
	2015		2014
	(unaudited)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	355	$	359
Income tax payments, net of refunds		37		154

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Acquisition of business:
Assets acquired	$	10	$	―
Liabilities assumed		(2)		―
Accrued purchase price		(5)		―
Cash paid	$	3	$	―

Accrued capital expenditures	$	459	$	385
Redemption of industrial development bonds		79		―
Increase in capital lease obligations for investment in property, plant and equipment		―		60
Dividends declared but not paid		179		166
Financing of build-to-suit property		61		49
Common dividends issued in stock		41		28
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended				Nine months ended
	September 30,				September 30,
	2015		2014		2015		2014
	(unaudited)
Operating revenues
Electric	$	1,140	$	1,133	$	2,819	$	2,892
Natural gas		90		100		349		391
Total operating revenues		1,230		1,233		3,168		3,283
Operating expenses
Cost of electric fuel and purchased power		427		441		906		1,036
Cost of natural gas		27		39		112		165
Operation and maintenance		251		276		723		784
Depreciation		152		134		446		395
Franchise fees and other taxes		73		67		193		177
Plant closure adjustment		―		―		(21)		(13)
Total operating expenses		930		957		2,359		2,544
Operating income		300		276		809		739
Other income, net		8		9		26		29
Interest expense		(51)		(51)		(155)		(152)
Income before income taxes		257		234		680		616
Income tax expense		(75)		(65)		(217)		(217)
Net income		182		169		463		399
Earnings attributable to noncontrolling interest		(12)		(12)		(20)		(20)
Earnings attributable to common shares	$	170	$	157	$	443	$	379
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
	SDG&E shareholder's equity
	Pretax		Income tax		Net-of-tax		Noncontrolling
	amount		expense		amount		interest (after-tax)		Total
	Three months ended September 30, 2015 and 2014
	(unaudited)
2015:
Net income	$	245	$	(75)	$	170	$	12	$	182
Other comprehensive loss:
Financial instruments		―		―		―		(1)		(1)
Total other comprehensive loss		―		―		―		(1)		(1)
Comprehensive income	$	245	$	(75)	$	170	$	11	$	181
2014:
Net income	$	222	$	(65)	$	157	$	12	$	169
Other comprehensive income:
Pension and other postretirement benefits		1		―		1		―		1
Financial instruments		―		―		―		4		4
Total other comprehensive income		1		―		1		4		5
Comprehensive income	$	223	$	(65)	$	158	$	16	$	174

	Nine months ended September 30, 2015 and 2014
	(unaudited)
2015:
Net income/Comprehensive income	$	660	$	(217)	$	443	$	20	$	463
2014:
Net income	$	596	$	(217)	$	379	$	20	$	399
Other comprehensive income:
Pension and other postretirement benefits		3		(1)		2		―		2
Financial instruments		―		―		―		3		3
Total other comprehensive income		3		(1)		2		3		5
Comprehensive income	$	599	$	(218)	$	381	$	23	$	404
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30,		December 31,
		2015		2014(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	20	$	8
Restricted cash			9		8
Accounts receivable – trade, net			411		285
Accounts receivable – other, net			27		35
Due from unconsolidated affiliates			1		1
Income taxes receivable			13		―
Inventories			71		73
Regulatory balancing accounts – net undercollected			495		711
Regulatory assets			146		54
Fixed-price contracts and other derivatives			20		44
Other			135		125
Total current assets			1,348		1,344

Other assets:
Restricted cash			12		11
Deferred taxes recoverable in rates			870		824
Other regulatory assets			1,000		1,086
Nuclear decommissioning trusts			1,060		1,131
Sundry			376		282
Total other assets			3,318		3,334

Property, plant and equipment:
Property, plant and equipment			16,131		15,478
Less accumulated depreciation			(4,105)		(3,860)
Property, plant and equipment, net ($390 and $410 at September 30, 2015 and December 31, 2014, respectively, related to VIE)			12,026		11,618
Total assets		$	16,692	$	16,296
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
		September 30,		December 31,
		2015		2014(1)
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt		$	44	$	246
Accounts payable			408		441
Due to unconsolidated affiliates			22		21
Income taxes payable			―		30
Deferred income taxes			243		53
Interest payable			49		40
Accrued compensation and benefits			110		124
Current portion of long-term debt			301		365
Asset retirement obligations			108		120
Fixed-price contracts and other derivatives			62		40
Customer deposits			71		71
Other			264		237
Total current liabilities			1,682		1,788
Long-term debt ($307 and $315 at September 30, 2015 and December 31, 2014, respectively, related to VIE)			4,477		4,319

Deferred credits and other liabilities:
Customer advances for construction			43		41
Pension and other postretirement benefit plan obligations, net of plan assets			227		216
Deferred income taxes			2,155		2,121
Deferred investment tax credits			19		22
Regulatory liabilities arising from removal obligations			1,538		1,557
Asset retirement obligations			740		754
Fixed-price contracts and other derivatives			170		153
Deferred credits and other			352		333
Total deferred credits and other liabilities			5,244		5,197

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			3,899		3,606
Accumulated other comprehensive income (loss)			(12)		(12)
Total SDG&E shareholder's equity			5,225		4,932
Noncontrolling interest			64		60
Total equity			5,289		4,992
Total liabilities and equity		$	16,692	$	16,296
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Nine months ended September 30,
	2015		2014
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	463	$	399
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		446		395
Deferred income taxes and investment tax credits		170		193
Plant closure adjustment		(21)		(13)
Fixed-price contracts and other derivatives		(3)		(5)
Other		(14)		(30)
Net change in other working capital components		136		(252)
Changes in other assets		(93)		106
Changes in other liabilities		10		28
Net cash provided by operating activities		1,094		821

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(835)		(790)
Purchases of nuclear decommissioning trust assets		(404)		(501)
Proceeds from sales by nuclear decommissioning trusts		431		498
Decrease in restricted cash		27		109
Increase in restricted cash		(29)		(96)
Other		―		(16)
Net cash used in investing activities		(810)		(796)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(150)		―
Issuances of long-term debt		388		100
Payments on long-term debt		(294)		(22)
Decrease in short-term debt, net		(202)		(59)
Capital distributions made by Otay Mesa VIE		(14)		(38)
Net cash used in financing activities		(272)		(19)

Increase in cash and cash equivalents		12		6
Cash and cash equivalents, January 1		8		27
Cash and cash equivalents, September 30	$	20	$	33

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	141	$	136
Income tax payments (refunds), net		62		(4)

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued capital expenditures	$	142	$	118
Increase in capital lease obligations for investment in property, plant and equipment		―		60
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
	(unaudited)

Operating revenues	$	620	$	855	$	2,448	$	2,857
Operating expenses
Cost of natural gas		163		237		626		1,066
Operation and maintenance		325		326		985		968
Depreciation		116		109		342		321
Franchise fees and other taxes		29		30		94		98
Total operating expenses		633		702		2,047		2,453
Operating (loss) income		(13)		153		401		404
Other income, net		8		6		25		13
Interest income		―		―		3		―
Interest expense		(23)		(17)		(61)		(50)
(Loss) income before income taxes		(28)		142		368		367
Income tax benefit (expense)		20		(44)		(91)		(110)
Net (loss) income		(8)		98		277		257
Preferred dividend requirements		―		―		(1)		(1)
(Losses) earnings attributable to common shares	$	(8)	$	98	$	276	$	256
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Pretax		Income tax		Net-of-tax
	amount		benefit (expense)		amount
	Three months ended September 30, 2015 and 2014
	(unaudited)
2015:
Net loss/Comprehensive loss	$	(28)	$	20	$	(8)
2014:
Net income	$	142	$	(44)	$	98
Other comprehensive income:
Pension and other postretirement benefits		4		(2)		2
Total other comprehensive income		4		(2)		2
Comprehensive income	$	146	$	(46)	$	100

	Nine months ended September 30, 2015 and 2014
	(unaudited)
2015:
Net income/Comprehensive income	$	368	$	(91)	$	277
2014:
Net income	$	367	$	(110)	$	257
Other comprehensive income:
Pension and other postretirement benefits		4		(2)		2
Total other comprehensive income		4		(2)		2
Comprehensive income	$	371	$	(112)	$	259
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30,		December 31,
		2015		2014(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	123	$	85
Accounts receivable – trade, net			301		586
Accounts receivable – other, net			69		51
Due from unconsolidated affiliates			220		4
Income taxes receivable			25		5
Inventories			192		181
Regulatory balancing accounts – net undercollected			90		35
Regulatory assets			7		5
Other			39		36
Total current assets			1,066		988

Other assets:
Regulatory assets arising from pension obligations			665		617
Other regulatory assets			543		472
Sundry			176		140
Total other assets			1,384		1,229

Property, plant and equipment:
Property, plant and equipment			13,739		12,886
Less accumulated depreciation			(4,834)		(4,642)
Property, plant and equipment, net			8,905		8,244
Total assets		$	11,355	$	10,461
(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)
		September 30,		December 31,
		2015		2014(1)
		(unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Short-term debt		$	―	$	50
Accounts payable – trade			355		532
Accounts payable – other			77		88
Due to unconsolidated affiliates			51		13
Deferred income taxes			171		53
Accrued compensation and benefits			144		129
Current portion of long-term debt			9		―
Customer deposits			74		75
Other			164		149
Total current liabilities			1,045		1,089

Long-term debt			2,498		1,906
Deferred credits and other liabilities:
Customer advances for construction			102		102
Pension obligation, net of plan assets			682		633
Deferred income taxes			1,270		1,212
Deferred investment tax credits			14		16
Regulatory liabilities arising from removal obligations			1,158		1,167
Asset retirement obligations			1,286		1,255
Deferred credits and other			293		300
Total deferred credits and other liabilities			4,805		4,685

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			2,137		1,911
Accumulated other comprehensive income (loss)			(18)		(18)
Total shareholders' equity			3,007		2,781
Total liabilities and shareholders' equity		$	11,355	$	10,461
(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)
	Nine months ended September 30,
	2015		2014
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	277	$	257
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		342		321
Deferred income taxes and investment tax credits		98		94
Other		(18)		(2)
Net change in other working capital components		48		(19)
Changes in other assets		(57)		(70)
Changes in other liabilities		―		15
Net cash provided by operating activities		690		596

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(946)		(764)
Increase in loans to affiliates, net		(250)		(281)
Net cash used in investing activities		(1,196)		(1,045)

CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends paid		(1)		(1)
Issuances of long-term debt		599		747
Repayment of long-term debt		―		(250)
Decrease in short-term debt, net		(50)		(42)
Other		(4)		(7)
Net cash provided by financing activities		544		447

Increase (decrease) in cash and cash equivalents		38		(2)
Cash and cash equivalents, January 1		85		27
Cash and cash equivalents, September 30	$	123	$	25

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	53	$	43
Income tax payments, net		11		19

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued capital expenditures	$	172	$	137
Dividends declared but not paid		50		―
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. GENERAL

IMPACT OF SEASONALIZATION AT SEMPRA ENERGY AND SOUTHERN CALIFORNIA GAS COMPANY

In the first quarter of 2015, Southern California Gas Company (SoCalGas) adopted a California Public Utilities Commission (CPUC) decision in the Triennial Cost Allocation Proceeding (TCAP) requiring SoCalGas to recognize annual authorized revenue for core natural gas customers using seasonal factors established in the TCAP, instead of recognizing such revenue ratably over the year as was previously required. This “seasonalization” resulted in $158 million lower operating revenues and $113 million lower earnings for both Sempra Energy and SoCalGas for the three months ended September 30, 2015 compared to the same period in 2014, and $67 million lower operating revenues and $48 million lower earnings for both Sempra Energy and SoCalGas for the first nine months of 2015 compared to the same period in 2014. While this seasonalization will cause variability in comparable revenue and earnings from quarter to quarter within the year, it will not impact full-year 2015 results nor have any impact on cash flows. Accordingly, substantially all of SoCalGas’ annual earnings will be recognized in the first and fourth quarters of the year. We discuss the CPUC decision further in Note 10.

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 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, 2014 (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 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 September 30, 2015 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, 2014 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2014 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. 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, Sempra Natural Gas’ Mobile Gas and Willmut Gas, and Sempra Mexico’s Ecogas prepare their financial statements in accordance with U.S. GAAP provisions governing regulated operations, as we discuss 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 2014-09) and ASU 2015-14, “Revenue from Contracts with Customers: Deferral of the Effective Date” (ASU 2015-14): ASU 2014-09 provides accounting guidance for revenue arising 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.

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 have not yet selected the year in which we will adopt the standard or our transition method, nor have we determined the effect of the standard on our ongoing financial reporting.

ASU 2015-03, “Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) and ASU 2015-15, “Interest - Imputation of Interest: Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” (ASU 2015-15): ASU 2015-03 provides guidance on the financial statement presentation of debt issuance costs and requires an entity to present debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related long-term debt liability. This guidance must be applied using a full retrospective approach for all periods presented in the period of adoption.

We will adopt ASU 2015-03 for our annual reporting period ending December 31, 2015, and the adoption will not affect our results of operations or cash flows. Deferred debt issuance costs that are the subject of ASU 2015-03 are included in Sundry on the Sempra Energy, SDG&E and SoCalGas Condensed Consolidated Balance Sheets and total $78 million, $32 million, and $18 million at September 30, 2015, respectively, and $72 million, $33 million, and $15 million at December 31, 2014, respectively.

ASU 2015-15 clarifies ASU 2015-03 to provide additional guidance related to line-of-credit arrangements and states that the Securities and Exchange Commission staff would not object to an entity continuing to defer and present costs related to line-of-credit arrangements as an asset and subsequently amortizing the deferred costs ratably over the term of the line-of-credit arrangements, regardless of whether there are any outstanding borrowings on the line-of-credit arrangements. We will adopt ASU 2015-15 for our annual reporting period ending December 31, 2015 and will continue to include deferred costs related to our line-of-credit arrangements that are the subject of ASU 2015-15 in Sundry on the Sempra Energy, SDG&E and SoCalGas Condensed Consolidated Balance Sheets.

ASU 2015-16, “Business Combinations – Simplifying the Accounting for Measurement-Period Adjustments” (ASU 2015-16): ASU 2015-16 eliminates the requirement that acquirers in a business combination account for measurement-period adjustments retrospectively. Instead, the acquirers will recognize measurement-period adjustments during the period in which they determine the amounts, including the effect on earnings of any amounts that would have been recorded in previous periods if the accounting had been completed at the acquisition date. We will adopt ASU 2015-16 for our annual reporting period ending December 31, 2015. Any subsequent measurement-period adjustments to the purchase price allocation related to the acquisition of Gasoductos de Chihuahua that we discuss in Note 3 will occur after the adoption of ASU 2015-16 and will be recognized in the period in which the adjustments are determined.

NOTE 3. ACQUISITION AND DIVESTITURE ACTIVITY

PENDING 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). 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), increasing its interest from 50 percent to 100 percent. GdC develops and operates energy infrastructure in Mexico. The assets involved in the acquisition include three natural gas pipelines, an ethane pipeline, and a liquid petroleum gas pipeline and associated storage terminal. The transaction excludes the Los Ramones Norte pipeline that IEnova will continue to develop under a separate joint venture with PEMEX, through which IEnova’s interest in the project will remain at the current 25 percent. IEnova shareholders approved the transaction in September 2015. The transaction is subject to satisfactory completion of the Mexican anti-trust review and other customary closing conditions and is expected to close by the end of 2015.

After financing at the IEnova level, we expect the acquisition to be accretive to Sempra Energy’s diluted earnings per share, based on the joint venture’s strong historical performance. We expect the transaction to have additional benefits, including an ongoing relationship with PEMEX for joint development of new projects in the future; opportunities for asset optimization and expansion into areas such as the transportation and storage of refined products; and a larger platform and presence in Mexico to participate in energy sector reform.

IEnova currently accounts for its 50-percent interest in GdC as an equity method investment. At closing, GdC will become a wholly owned, consolidated subsidiary of IEnova. We anticipate that we will recognize a noncash gain associated with the remeasurement of our equity interest in GdC upon consummation of the transaction, however, as the transaction has not yet closed, we are unable to reasonably estimate the gain at this time.

We expect the acquisition to be funded with a combination of debt and equity at IEnova. Sempra Global has committed to IEnova to provide approximately $1.325 billion of interim financing for the transaction. If IEnova elects to borrow this money, it expects to repay all or a substantial portion of the loan with proceeds from a planned equity offering. IEnova is also arranging to receive bank commitments of up to $1.0 billion to have an alternate source of capital to repay a portion of the interim financing from Sempra Global. Sempra Energy intends to participate in the planned equity offering with proceeds of dividends from IEnova that otherwise would be repatriated to the U.S.

MESQUITE POWER SALE

Sempra Natural Gas

In April 2015, Sempra Natural Gas sold the remaining 625-megawatt (MW) block of the Mesquite Power plant, together with a related power sales contract, for net cash proceeds of $347 million. We recognized a pretax gain on the sale of $61 million ($36 million after-tax), included in Gain on Sale of Equity Interests and Assets on our Condensed Consolidated Statement of Operations for the nine months ended September 30, 2015. The asset was classified as held for sale at December 31, 2014.

SALE OF EQUITY INTERESTS AND JOINT VENTURE INVESTMENT

During the nine months ended September 30, 2014, Sempra Energy completed the sale of equity interests in various subsidiaries that were previously wholly owned. The following table summarizes the deconsolidation of those subsidiaries, and we discuss each transaction below:

DECONSOLIDATION OF SUBSIDIARIES
(Dollars in millions)
	Energía Sierra Juárez		Copper Mountain Solar 3		Sempra Energy Consolidated
	At July 16, 2014		At March 13, 2014
Proceeds from sale, net of negligible transaction costs	$	26	$	68	$	94
Cash		(2)		(2)		(4)
Other current assets		(11)		―		(11)
Property, plant and equipment, net		(137)		(247)		(384)
Other assets		(16)		(11)		(27)
Accounts payable and accrued expenses		10		82		92
Due to affiliate		39		―		39
Long-term debt, including current portion		82		97		179
Other liabilities		7		3		10
Accumulated other comprehensive income		(5)		(2)		(7)
Gain on sale of equity interests		(19)		(27)		(46)
(Increase) in equity method investments upon deconsolidation	$	(26)	$	(39)	$	(65)

Sempra Mexico

In July 2014, Sempra Mexico completed the sale of a 50-percent interest in the 155-MW first phase of its Energía Sierra Juárez wind project to a wholly owned subsidiary of InterGen N.V. for cash proceeds of $24 million, net of $2 million cash sold. Sempra Mexico recognized a pretax gain on the sale of $19 million ($14 million after-tax) included in Gain on Sale of Equity Interests and Assets on our Condensed Consolidated Statements of Operations for the three months and nine months ended September 30, 2014. The gain on sale included a $7 million after-tax gain attributable to the remeasurement of the retained investment to fair value. Our remaining 50-percent interest in Energía Sierra Juárez is accounted for under the equity method.

Sempra Renewables

In March 2014, Sempra Renewables formed a joint venture with Consolidated Edison Development (Con Edison Development), a non-related party, by selling a 50-percent interest in its 250-MW Copper Mountain Solar 3 solar power facility for $66 million in cash, net of $2 million cash sold. Sempra Renewables recognized a pretax gain on the sale of $27 million ($16 million after-tax), included in Gain on Sale of Equity Interests and Assets on our Condensed Consolidated Statement of Operations for the nine months ended September 30, 2014. Our remaining 50-percent interest in Copper Mountain Solar 3 is accounted for under the equity method. Based on the nature of the underlying assets, this investment is considered in-substance real estate. Therefore, in accordance with applicable U.S. GAAP, the Copper Mountain Solar 3 equity method investment was measured at historical cost and no portion of the gain was attributable to a remeasurement of the retained investment to fair value.

In May 2014, Sempra Renewables invested $109 million (and an additional $12 million in November 2014, as adjusted for financial position at closing) to become a 50-percent partner with Con Edison Development in four fully operating solar facilities in California. We discuss our investment in the California solar partnership further in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

In March 2015, Sempra Renewables acquired a 100-percent interest in the Black Oak Getty Wind project, a 78-MW wind farm under development in Stearns County, Minnesota. The wind farm has a 20-year power purchase agreement with Minnesota Municipal Power Agency. The total acquisition cost for the project is $8 million.

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

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

SEMPRA RENEWABLES

In addition to Sempra Renewables’ investment in the California solar partnership discussed in Note 3 above, during the nine months ended September 30, 2015 and 2014, Sempra Renewables invested cash of $18 million and $76 million, respectively, in its other renewable energy joint ventures.

SEMPRA NATURAL GAS

During the nine months ended September 30, 2015, Sempra Natural Gas invested $10 million of cash in its joint venture, Cameron LNG Holdings, LLC (Cameron LNG Holdings or Cameron LNG JV), and capitalized $36 million of interest related to this equity method investment that has not commenced planned principal operations.

In April 2015, Sempra Natural Gas invested $113 million of cash in its equity method investment, Rockies Express Pipeline LLC, a partnership that operates the Rockies Express pipeline, to repay project debt that matured in early 2015.

NOTE 5. OTHER FINANCIAL DATA

INVENTORIES

The components of inventories by segment are as follows:

INVENTORY BALANCES
(Dollars in millions)
	Natural gas				Liquefied natural gas				Materials and supplies				Total
	September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014
SDG&E	$	4	$	8	$	―	$	―	$	67	$	65	$	71	$	73
SoCalGas		162		155		―		―		30		26		192		181
Sempra South American
Utilities		―		―		―		―		34		33		34		33
Sempra Mexico		―		―		7		9		10		9		17		18
Sempra Renewables		―		―		―		―		2		2		2		2
Sempra Natural Gas		95		83		4		5		1		1		100		89
Sempra Energy
Consolidated	$	261	$	246	$	11	$	14	$	144	$	136	$	416	$	396

GOODWILL

We discuss goodwill in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. The decrease in goodwill from $931 million at December 31, 2014 to $847 million at September 30, 2015 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 (VIE)

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

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. We determine if SDG&E 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, as we discuss below.

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 the power plant 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 $64 million at September 30, 2015 and $60 million at December 31, 2014 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 $317 million at September 30, 2015, the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is secured by OMEC’s property, plant and equipment. SDG&E is not a party to the loan agreement and does not have any additional implicit or explicit financial responsibility to OMEC LLC. The loan fully matures in April 2019 and bears interest at rates varying with market rates. In addition, OMEC LLC has entered into interest rate swap agreements to moderate its exposure to interest rate changes. We provide additional information concerning the interest rate swaps in Note 7.

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

AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Operating expenses
Cost of electric fuel and purchased power	$	(27)	$	(27)	$	(66)	$	(67)
Operation and maintenance		3		3		13		13
Depreciation		7		7		19		21
Total operating expenses		(17)		(17)		(34)		(33)
Operating income		17		17		34		33
Interest expense		(5)		(5)		(14)		(13)
Income before income taxes/Net income		12		12		20		20
Earnings attributable to noncontrolling interest		(12)		(12)		(20)		(20)
Earnings attributable to common shares	$	―	$	―	$	―	$	―

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

Cameron LNG JV

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 was $956 million and $1,007 million at September 30, 2015 and December 31, 2014, respectively. Our maximum exposure to loss includes the carrying value of our investment and the guarantees discussed in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Variable Interest Entities

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. 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 September 30, 2015. 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.

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 September 30,
	2015		2014		2015		2014
Service cost	$	27	$	23	$	5	$	6
Interest cost		38		39		10		13
Expected return on assets		(42)		(42)		(17)		(15)
Amortization of:
Prior service cost (credit)		3		3		(1)		(2)
Actuarial loss		9		3		―		―
Settlements and special termination benefits		4		5		―		5
Regulatory adjustment		(27)		6		4		5
Total net periodic benefit cost	$	12	$	37	$	1	$	12

	Nine months ended September 30,
	2015		2014		2015		2014
Service cost	$	86	$	75	$	19	$	18
Interest cost		116		121		33		37
Expected return on assets		(130)		(128)		(51)		(47)
Amortization of:
Prior service cost (credit)		8		8		(2)		(4)
Actuarial loss		28		13		―		―
Settlements and special termination benefits		4		14		―		5
Regulatory adjustment		(86)		(18)		4		5
Total net periodic benefit cost	$	26	$	85	$	3	$	14

NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
	Pension benefits				Other postretirement benefits
	Three months ended September 30,
	2015		2014		2015		2014
Service cost	$	6	$	8	$	1	$	2
Interest cost		9		10		2		3
Expected return on assets		(14)		(13)		(2)		(2)
Amortization of:
Actuarial loss		3		1		―		―
Special termination benefits		―		―		―		5
Regulatory adjustment		(3)		6		(1)		4
Total net periodic benefit cost	$	1	$	12	$	―	$	12

	Nine months ended September 30,
	2015		2014		2015		2014
Service cost	$	22	$	23	$	5	$	5
Interest cost		29		32		6		7
Expected return on assets		(41)		(41)		(8)		(8)
Amortization of:
Prior service cost		1		1		2		2
Actuarial loss		7		3		―		―
Settlements and special termination benefits		―		2		―		5
Regulatory adjustment		(15)		7		(5)		1
Total net periodic benefit cost	$	3	$	27	$	―	$	12

NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
	Pension benefits				Other postretirement benefits
	Three months ended September 30,
	2015		2014		2015		2014
Service cost	$	17	$	13	$	3	$	4
Interest cost		25		24		8		9
Expected return on assets		(25)		(26)		(14)		(12)
Amortization of:
Prior service cost (credit)		2		2		(2)		(2)
Actuarial loss		5		1		―		―
Settlement		―		4		―		―
Regulatory adjustment		(24)		―		5		1
Total net periodic benefit cost	$	―	$	18	$	―	$	―

	Nine months ended September 30,
	2015		2014		2015		2014
Service cost	$	55	$	45	$	13	$	12
Interest cost		74		75		26		28
Expected return on assets		(79)		(78)		(42)		(38)
Amortization of:
Prior service cost (credit)		6		6		(6)		(6)
Actuarial loss		16		5		―		―
Settlement		―		4		―		―
Regulatory adjustment		(71)		(25)		9		4
Total net periodic benefit cost	$	1	$	32	$	―	$	―

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 2015:

BENEFIT PLAN CONTRIBUTIONS
(Dollars in millions)
	Sempra Energy
	Consolidated		SDG&E		SoCalGas
Contributions through September 30, 2015:
Pension plans	$	27	$	2	$	1
Other postretirement benefit plans		3		―		―
Total expected contributions in 2015:
Pension plans	$	36	$	3	$	7
Other postretirement benefit plans		11		7		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 $459 million and $512 million at September 30, 2015 and December 31, 2014, respectively.

EARNINGS PER SHARE

The following table provides the per share computations for our earnings for the three months and nine months ended September 30, 2015 and 2014. Basic earnings per common share (EPS) is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

EARNINGS PER SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
		Three months ended September 30,				Nine months ended September 30,
		2015		2014		2015		2014
Numerator:
Earnings/Income attributable to common shares		$	248	$	348	$	980	$	864

Denominator:
Weighted-average common shares
	outstanding for basic EPS(1)		248,432		246,137		248,090		245,703
Dilutive effect of stock options, restricted
	stock awards and restricted stock units		2,592		4,634		2,575		4,575
Weighted-average common shares
	outstanding for diluted EPS		251,024		250,771		250,665		250,278

Earnings per share:
Basic		$	1.00	$	1.41	$	3.95	$	3.52
Diluted			0.99		1.39		3.91		3.45
(1)	Includes fully vested restricted stock units of 504 and 222 held in our Deferred Compensation Plan for the three months ended September 30, 2015 and 2014, respectively, and 486 and 209 for the nine months ended September 30, 2015 and 2014, 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). We had no such antidilutive stock options outstanding for the three months or nine months ended September 30, 2015 or 2014. For the three months and nine months ended September 30, 2015 and 2014, 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 RSUs from the application of unearned compensation in the treasury stock method for the three months and nine months ended September 30, 2015. There were no such antidilutive RSAs or RSUs for the three months or nine months ended September 30, 2014.

Our performance-based RSUs include awards that vest at the end of three-year (for awards granted in 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.

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 2,001,020 and 2,047,656 for the three months and nine months ended September 30, 2015, respectively, and 844,251 and 971,943 for the three months and nine months ended September 30, 2014, 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-month periods ended September 30, 2015 and 2014, respectively, and $22 million for each of the nine-month periods ended September 30, 2015 and 2014. Pursuant to our Sempra Energy share-based compensation plans, Sempra Energy’s compensation committee granted 301,319 TSR RSUs, 76,675 EPS RSUs and 133,159 RSUs issued either as service-based awards or in connection with certain other performance goals during the nine months ended September 30, 2015, primarily in January.

During the nine months ended September 30, 2015, IEnova issued 278,538 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, primarily at the California Utilities, an allowance for funds used during construction (AFUDC) related to both debt and equity financing of construction projects.

Pipeline projects currently under construction by Sempra Mexico and Sempra Natural Gas that are both subject to certain regulation and meet U.S. GAAP regulatory accounting requirements record the impact of AFUDC related to equity.

Sempra International’s and Sempra U.S. Gas & Power’s businesses capitalize interest costs incurred to finance capital projects and interest on equity method investments that have not commenced planned principal operations. The California Utilities also capitalize certain interest costs.

The following table shows capitalized financing costs for the three months and nine months ended September 30, 2015 and 2014.

CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
Sempra Energy Consolidated:
AFUDC related to debt	$	6	$	5	$	19	$	15
AFUDC related to equity		26		28		84		77
Other capitalized financing costs		18		6		52		22
Total Sempra Energy Consolidated	$	50	$	39	$	155	$	114
SDG&E:
AFUDC related to debt	$	3	$	3	$	10	$	10
AFUDC related to equity		9		8		27		26
Total SDG&E	$	12	$	11	$	37	$	36
SoCalGas:
AFUDC related to debt	$	3	$	2	$	9	$	5
AFUDC related to equity		10		7		29		18
Other capitalized financing costs		1		―		1		―
Total SoCalGas	$	14	$	9	$	39	$	23

COMPREHENSIVE INCOME

The following tables present the changes in Accumulated Other Comprehensive Income (Loss) (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)
				Pension and other
				postretirement benefits
		Foreign								Total
		currency		Unamortized		Unamortized				accumulated other
		translation		net actuarial		prior service		Financial		comprehensive
		adjustments		gain (loss)		cost		instruments		income (loss)
		Three months ended September 30, 2015 and 2014
2015:
Balance as of June 30, 2015		$	(427)	$	(81)	$	(2)	$	(86)	$	(596)
Other comprehensive loss before
reclassifications			(92)		―		―		(79)		(171)
Amounts reclassified from accumulated other
comprehensive income			―		5		―		1		6
Net other comprehensive (loss) income			(92)		5		―		(78)		(165)
Balance as of September 30, 2015		$	(519)	$	(76)	$	(2)	$	(164)	$	(761)
2014:
Balance as of June 30, 2014		$	(170)	$	(65)	$	―	$	(38)	$	(273)
Other comprehensive loss before
reclassifications			(100)		―		―		(2)		(102)
Amounts reclassified from accumulated other
comprehensive income (loss)			―		5		―		(1)		4
Net other comprehensive (loss) income			(100)		5		―		(3)		(98)
Balance as of September 30, 2014		$	(270)	$	(60)	$	―	$	(41)	$	(371)

		Nine months ended September 30, 2015 and 2014
2015:
Balance as of December 31, 2014		$	(322)	$	(83)	$	(2)	$	(90)	$	(497)
Other comprehensive loss before
reclassifications			(197)		―		―		(76)		(273)
Amounts reclassified from accumulated other
comprehensive income			―		7		―		2		9
Net other comprehensive (loss) income			(197)		7		―		(74)		(264)
Balance as of September 30, 2015		$	(519)	$	(76)	$	(2)	$	(164)	$	(761)
2014:					.
Balance as of December 31, 2013		$	(129)	$	(73)	$	―	$	(26)	$	(228)
Other comprehensive loss before
reclassifications			(141)		―		―		(28)		(169)
Amounts reclassified from accumulated other
comprehensive income			―		13		―		13		26
Net other comprehensive (loss) income			(141)		13		―		(15)		(143)
Balance as of September 30, 2014		$	(270)	$	(60)	$	―	$	(41)	$	(371)
(1)	All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SAN DIEGO GAS & ELECTRIC COMPANY
(Dollars in millions)
		Pension and other
		postretirement benefits
						Total
		Unamortized		Unamortized		accumulated other
		net actuarial		prior service		comprehensive
		gain (loss)		credit		income (loss)
		Three months ended September 30, 2015 and 2014
2015:
Balance as of June 30 and September 30, 2015		$	(13)	$	1	$	(12)
2014:
Balance as of June 30, 2014		$	(9)	$	1	$	(8)
Amounts reclassified from accumulated other
comprehensive income			1		―		1
Net other comprehensive income			1		―		1
Balance as of September 30, 2014		$	(8)	$	1	$	(7)

		Nine months ended September 30, 2015 and 2014
2015:
Balance as of December 31, 2014 and September 30, 2015		$	(13)	$	1	$	(12)
2014:
Balance as of December 31, 2013		$	(10)	$	1	$	(9)
Amounts reclassified from accumulated other
comprehensive income			2		―		2
Net other comprehensive income			2		―		2
Balance as of September 30, 2014		$	(8)	$	1	$	(7)
(1)	All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SOUTHERN CALIFORNIA GAS COMPANY
(Dollars in millions)
		Pension and other
		postretirement benefits
								Total
		Unamortized		Unamortized				accumulated other
		net actuarial		prior service		Financial		comprehensive
		gain (loss)		credit		instruments		income (loss)
		Three months ended September 30, 2015 and 2014
2015:
Balance as of June 30 and September 30, 2015		$	(5)	$	1	$	(14)	$	(18)
2014:
Balance as of June 30, 2014		$	(5)	$	1	$	(14)	$	(18)
Amounts reclassified from accumulated other
comprehensive income			2		―		―		2
Net other comprehensive income			2		―		―		2
Balance as of September 30, 2014		$	(3)	$	1	$	(14)	$	(16)

		Nine months ended September 30, 2015 and 2014
2015:
Balance as of December 31, 2014 and September 30, 2015		$	(5)	$	1	$	(14)	$	(18)
2014:
Balance as of December 31, 2013		$	(5)	$	1	$	(14)	$	(18)
Amounts reclassified from accumulated other
comprehensive income			2		―		―		2
Net other comprehensive income			2		―		―		2
Balance as of September 30, 2014		$	(3)	$	1	$	(14)	$	(16)
(1)	All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated		Amounts reclassified
other comprehensive income (loss)		from accumulated other				Affected line item on Condensed
components		comprehensive income (loss)				Consolidated Statements of Operations
		Three months ended September 30,
		2015		2014
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments		$	5	$	8	Interest Expense
Interest rate instruments			―		(5)	Gain on Sale of Equity Interests and Assets
Interest rate instruments			3		2	Equity Earnings, Before Income Tax
Commodity contracts not subject						Revenues: Energy-Related
	to rate recovery		(3)		(2)	Businesses
Total before income tax			5		3
			(1)		(1)	Income Tax Expense
Net of income tax			4		2
			(3)		(3)	Earnings Attributable to Noncontrolling Interests
		$	1	$	(1)

Pension and other postretirement benefits:
Amortization of actuarial loss		$	7	$	8	See note (1) below
			(2)		(3)	Income Tax Expense
Net of income tax		$	5	$	5

Total reclassifications for the period, net of tax		$	6	$	4
SDG&E:
Financial instruments:
Interest rate instruments		$	3	$	3	Interest Expense
			(3)		(3)	Earnings Attributable to Noncontrolling Interest
		$	―	$	―

Pension and other postretirement benefits:
Amortization of actuarial loss		$	―	$	1	See note (1) below
			―		―	Income Tax Expense
Net of income tax		$	―	$	1

Total reclassifications for the period, net of tax		$	―	$	1
SoCalGas:
Pension and other postretirement benefits:
Amortization of actuarial loss		$	―	$	4	See note (1) below
			―		(2)	Income Tax Expense
Net of income tax		$	―	$	2

Total reclassifications for the period, net of tax		$	―	$	2
(1)	Amounts are included in the computation of net periodic benefit cost (see "Pension and Other Postretirement Benefits" above).

RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated		Amount reclassified
other comprehensive income (loss)		from accumulated other				Affected line item on Condensed
components		comprehensive income (loss)				Consolidated Statements of Operations
		Nine months ended September 30,
		2015		2014
Sempra Energy Consolidated:
Financial instruments:
Interest rate and foreign exchange instruments		$	14	$	17	Interest Expense
Interest rate instruments			―		(3)	Gain on Sale of Equity Interests and Assets
Interest rate instruments			9		7	Equity Earnings, Before Income Tax
Commodity contracts not subject to						Revenues: Energy-Related
	rate recovery		(10)		8	Businesses
Total before income tax			13		29
			(1)		(8)	Income Tax Expense
Net of income tax			12		21
			(10)		(8)	Earnings Attributable to Noncontrolling Interests
		$	2	$	13

Pension and other postretirement benefits:
Amortization of actuarial loss		$	11	$	21	See note (1) below
			(4)		(8)	Income Tax Expense
Net of income tax		$	7	$	13

Total reclassifications for the period, net of tax		$	9	$	26
SDG&E:
Financial instruments:
Interest rate instruments		$	9	$	8	Interest Expense
			(9)		(8)	Earnings Attributable to Noncontrolling Interest
		$	―	$	―

Pension and other postretirement benefits:
Amortization of actuarial loss		$	―	$	3	See note (1) below
			―		(1)	Income Tax Expense
Net of income tax		$	―	$	2

Total reclassifications for the period, net of tax		$	―	$	2
SoCalGas:
Pension and other postretirement benefits:
Amortization of actuarial loss		$	―	$	4	See note (1) below
			―		(2)	Income Tax Expense
Net of income tax		$	―	$	2

Total reclassifications for the period, net of tax		$	―	$	2
(1)	Amounts are included in the computation of net periodic benefit cost (see "Pension and Other Postretirement Benefits" above).

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS

The following tables provide reconciliations of changes in Sempra Energy’s, SDG&E’s and SoCalGas’ shareholders’ equity and noncontrolling interests for the nine months ended September 30, 2015 and 2014.

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, 2014		$	11,326	$	774	$	12,100
Comprehensive income			717		56		773
Preferred dividends of subsidiary			(1)		―		(1)
Share-based compensation expense			39		―		39
Common stock dividends declared			(520)		―		(520)
Issuance of common stock			82		―		82
Repurchases of common stock			(74)		―		(74)
Tax benefit related to share-based compensation			56		―		56
Equity contributed by noncontrolling interest			―		1		1
Distributions to noncontrolling interests			―		(60)		(60)
Balance at September 30, 2015		$	11,625	$	771	$	12,396
Balance at December 31, 2013		$	11,008	$	842	$	11,850
Comprehensive income			722		66		788
Preferred dividends of subsidiary			(1)		―		(1)
Share-based compensation expense			35		―		35
Common stock dividends declared			(486)		―		(486)
Issuance of common stock			71		―		71
Repurchases of common stock			(38)		―		(38)
Tax benefit related to share-based compensation			22		―		22
Equity contributed by noncontrolling interest			―		1		1
Distributions to noncontrolling interests			―		(85)		(85)
Balance at September 30, 2014		$	11,333	$	824	$	12,157
(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, 2014	$	4,932	$	60	$	4,992
Comprehensive income		443		20		463
Common stock dividends declared		(150)		―		(150)
Distributions to noncontrolling interest		―		(16)		(16)
Balance at September 30, 2015	$	5,225	$	64	$	5,289
Balance at December 31, 2013	$	4,628	$	91	$	4,719
Comprehensive income		381		23		404
Distributions to noncontrolling interest		―		(37)		(37)
Balance at September 30, 2014	$	5,009	$	77	$	5,086

SHAREHOLDERS' EQUITY ― SOCALGAS
(Dollars in millions)
		SoCalGas
		shareholders'
		equity
Balance at December 31, 2014	$	2,781
Comprehensive income		277
Preferred stock dividends declared		(1)
Common stock dividends declared		(50)
Balance at September 30, 2015	$	3,007
Balance at December 31, 2013	$	2,549
Comprehensive income		259
Preferred stock dividends declared		(1)
Balance at September 30, 2014	$	2,807

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

Preferred Stock

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

Other Noncontrolling Interests

At September 30, 2015 and December 31, 2014, we reported the following noncontrolling ownership interests held by others (not including preferred shareholders) recorded in Other Noncontrolling Interests in Total Equity on Sempra Energy’s Condensed Consolidated Balance Sheets:

OTHER NONCONTROLLING INTERESTS
(Dollars in millions)
		Percent ownership held by others
		September 30,		December 31,			September 30,		December 31,
		2015		2014			2015		2014
SDG&E:
Otay Mesa VIE		100	%	100	%	$	64	$	60
Sempra South American Utilities:
Chilquinta Energía subsidiaries(1)		23.5 – 43.4		23.6 – 43.4			20		23
Luz del Sur		16.4		16.4			171		177
Tecsur		9.8		9.8			3		4
Sempra Mexico:
IEnova, S.A.B. de C.V.		18.9		18.9			455		452
Sempra Natural Gas:
Bay Gas Storage Company, Ltd.		9.1		9.1			25		23
Liberty Gas Storage, LLC		23.7		25.0			12		14
Southern Gas Transmission Company		49.0		49.0			1		1
Total Sempra Energy						$	751	$	754
(1)	Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages amongst these subsidiaries.

TRANSACTIONS WITH AFFILIATES

Current and noncurrent amounts due from unconsolidated affiliates on the Sempra Energy Condensed Consolidated Balance Sheets are as follows:

DUE FROM UNCONSOLIDATED AFFILIATES(1)
(Dollars in millions)
			September 30, 2015		December 31, 2014
Sempra South American Utilities:
Eletrans S.A.:
4% Note(2)		$	65	$	41
Sempra Mexico:
Affiliate of joint venture with Petróleos Mexicanos(3):
Note due November 13, 2017(4)(5)			3		44
Note due November 14, 2018(4)			41		40
Note due November 14, 2018(4)			34		33
Note due November 14, 2018(4)			8		8
Energía Sierra Juárez:
Note due June 15, 2018(6)			24		22
Other(7)			3		38
Total		$	178	$	226
(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., an affiliate of Chilquinta Energía.
(3)	Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company).
(4)	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 450 basis points (4.69 percent at September 30, 2015), to finance the Los Ramones Norte pipeline project.
(5)	In May 2015, $41 million was paid with proceeds from project financing at the affiliate.
(6)	U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 637.5 basis points (6.57 percent at September 30, 2015), to finance the first phase of the Energía Sierra Juárez wind project.
(7)	Amounts represent accounts receivable from various Sempra Renewables and Sempra Mexico joint venture investments.

Service Agreements

Sempra Energy, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Also, from time-to-time, SDG&E and SoCalGas may loan surplus cash to Sempra Energy at interest rates based on one-month commercial paper rates. Amounts due to/from affiliates are as follows:

AMOUNTS DUE TO AND FROM AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
		September 30, 2015		December 31, 2014
SDG&E:
Current:
Due from SoCalGas		$	1	$	―
Due from various affiliates			―		1
		$	1	$	1


Due to Sempra Energy		$	22	$	17
Due to SoCalGas			―		4
		$	22	$	21

Income taxes due from Sempra Energy(1)		$	41	$	16
SoCalGas:
Current:
Due from Sempra Energy(2)		$	220	$	―
Due from SDG&E			―		4
		$	220	$	4


Due to affiliate		$	50	$	―
Due to SDG&E			1		―
Due to Sempra Energy			―		13
		$	51	$	13


Income taxes due from Sempra Energy(1)		$	29	$	9
(1)	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.
(2)	Net receivable includes a loan to Sempra Energy of $250 million at September 30, 2015 at an interest rate of 0.10 percent.

Revenues from unconsolidated affiliates at SDG&E and SoCalGas are as follows:

REVENUES FROM UNCONSOLIDATED AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015			2014
SDG&E	$	3	$	2	$	8	$	8
SoCalGas		19		17		55		51

OTHER INCOME, NET

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

OTHER INCOME, NET
(Dollars in millions)
		Three months ended September 30,				Nine months ended September 30,
			2015		2014		2015		2014
Sempra Energy Consolidated:
Allowance for equity funds used during construction		$	26	$	28	$	84	$	77
Investment (losses) gains(1)			(12)		(3)		(5)		20
(Losses) gains on interest rate and foreign exchange instruments, net			(4)		(6)		(7)		3
Foreign currency losses			(3)		(2)		(6)		(1)
Sale of other investments			2		1		8		1
Electrical infrastructure relocation income(2)			―		4		4		7
Regulatory interest, net(3)			1		2		3		5
Sundry, net			2		5		7		6
Total		$	12	$	29	$	88	$	118
SDG&E:
Allowance for equity funds used during construction		$	9	$	8	$	27	$	26
Regulatory interest, net(3)			1		2		3		5
Sundry, net			(2)		(1)		(4)		(2)
Total		$	8	$	9	$	26	$	29
SoCalGas:
Allowance for equity funds used during construction		$	10	$	7	$	29	$	18
Sundry, net			(2)		(1)		(4)		(5)
Total		$	8	$	6	$	25	$	13
(1)	Represents investment (losses) gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
(2)	Income at Luz del Sur associated with the relocation of electrical infrastructure.
(3)	Interest on regulatory balancing accounts.

INCOME TAXES

INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
		Income tax	Effective				Effective
		expense	income			Income tax	income
		(benefit)	tax rate			expense	tax rate
		Three months ended September 30,
		2015				2014
Sempra Energy Consolidated	$	15	6	%	$	71	16	%
SDG&E		75	29			65	28
SoCalGas		(20)	71			44	31
		Nine months ended September 30,
		2015				2014
Sempra Energy Consolidated	$	276	22	%	$	291	24	%
SDG&E		217	32			217	35
SoCalGas		91	25			110	30

Changes in Income Tax Expense and Effective Income Tax Rates

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 are factored into the forecasted effective tax rate, and their impact is recognized proportionately over the year. The forecasted items, anticipated on a full year basis, may include, among others:

§	utility self-developed software expenditures

§	repairs to certain utility plant assets

§	renewable energy income tax credits

§	deferred income tax benefits related to renewable energy projects

§	exclusions from taxable income of the equity portion of AFUDC

§	depreciation on a certain portion of utility plant assets

§	U.S. tax on repatriation of current year earnings from non-U.S. subsidiaries

Items that cannot be reliably forecasted (e.g., adjustments related to 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 to income tax expense.

Sempra Energy Consolidated

The decrease in income tax expense in the three months ended September 30, 2015 was due to lower pretax income and a lower effective tax rate, primarily from:

§	$12 million higher favorable resolution of prior years’ income tax items in 2015;

§	$9 million higher income tax benefit in 2015 from foreign currency translation and inflation adjustments; and

§	$14 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries, as discussed below; offset by

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

The decrease in income tax expense in the nine months ended September 30, 2015 was due to a lower effective tax rate, offset by higher pretax income. The lower effective tax rate was primarily from:

§	$17 million charge in 2014 to reduce certain tax regulatory assets attributed to SDG&E’s investment in San Onofre Nuclear Generating Station (SONGS) that we discuss in Note 9;

§	$19 million higher favorable resolution of prior years’ income tax items in 2015;

§	$22 million higher income tax benefit in 2015 from foreign currency translation and inflation adjustments; and

§	$14 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries, as discussed below; offset by

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

Repatriated earnings are subject to U.S. income tax, and repatriation from Peru is subject to local country withholding tax. We no longer plan to repatriate current year 2015 earnings from our non-U.S. subsidiaries in Mexico due to IEnova’s pending acquisition of its joint venture partner’s 50-percent interest in GdC, which we discuss in Note 3. We plan to repatriate, in the future, current year earnings from certain of our non-U.S. subsidiaries in Peru, and accordingly, we are accruing tax expense on the current year earnings. Because this potential repatriation from Peru would only be from earnings since January 1, 2015, it does not change our current assertion that we intend to continue to indefinitely reinvest our cumulative undistributed non-U.S. earnings from prior years. Therefore, we do not intend to use these cumulative undistributed earnings as a source of funding for U.S. operations.

SDG&E

The increase in SDG&E’s income tax expense in the three months ended September 30, 2015 was due to higher pretax income and a higher effective tax rate, primarily from:

§	higher unfavorable impact on our effective tax rate in 2015 from the reversal through book depreciation of previously recognized tax benefits for a certain portion of utility fixed assets; offset by

§	higher exclusions from taxable income of the equity portion of AFUDC.

While SDG&E’s income tax expense remained the same in the nine months ended September 30, 2015, the effect of higher pretax income was offset by a lower effective tax rate, primarily from:

§	$17 million charge in 2014 to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS that we discuss in Note 9; and

§	$9 million higher favorable resolution of prior years’ income tax items in 2015.

The results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is not included in Sempra Energy’s federal or state income tax returns but is consolidated for financial statement purposes, and therefore, Sempra Energy Consolidated’s and SDG&E’s effective income tax rates are impacted by the VIE’s stand-alone effective income tax rate. We discuss Otay Mesa VIE above in “Variable Interest Entities.”

SoCalGas

SoCalGas’ income tax benefit in the three months ended September 30, 2015 compared to income tax expense in the same period in 2014 was due to a pretax loss in 2015 and a higher effective tax rate. The pretax loss was primarily due to recognizing core gas authorized revenue during interim periods based on seasonal factors beginning January 1, 2015 in accordance with the TCAP, compared to recognizing such revenue ratably over the year in 2014. We discuss the impact of the TCAP decision further in Note 10. The higher effective tax rate applied to the pretax loss was primarily due to:

§	$11 million higher favorable resolution of prior years’ income tax items in 2015; and

§	lower flow-through component of state income taxes.

The decrease in SoCalGas’ income tax expense in the nine months ended September 30, 2015 was mainly due to a lower effective tax rate, primarily from:

§	$14 million higher favorable resolution of prior years’ income tax items in 2015; and

§	higher exclusions from taxable income of the equity portion of AFUDC.

For SDG&E and SoCalGas, the CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the 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 and Sempra Natural Gas 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 September 30, 2015, Sempra Energy Consolidated had an aggregate of $4.1 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 September 30, 2015 was approximately $3.3 billion. Some of Sempra Energy’s subsidiaries, primarily our foreign operations, have additional general purpose credit facilities, aggregating $945 million at September 30, 2015. Available unused credit on these lines totaled $485 million at September 30, 2015.

Sempra Energy

Line of Credit at September 30, 2015

Sempra Energy had a $1.067 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. served as administrative agent for the syndicate of 24 lenders. Borrowings bore interest at benchmark rates plus a margin that varied with market index rates and Sempra Energy’s credit ratings. The facility required Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At September 30, 2015 and December 31, 2014, Sempra Energy was in compliance with this and all other financial covenants under the credit facility. The facility also provided for issuance of up to $635 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit.

At September 30, 2015, Sempra Energy had no outstanding borrowings or letters of credit supported by the facility.

Amended and Restated Line of Credit Effective October 13, 2015

On October 13, 2015, Sempra Energy entered into an amended and restated, five-year syndicated revolving credit agreement expiring in October 2020. The credit facility permits borrowings of up to $1 billion. Citibank, N.A. serves as administrative agent for the syndicate of 20 lenders and no single lender has greater than a 7-percent share. The credit facility amends, restates and supersedes Sempra Energy’s $1.067 billion credit agreement that was to expire in 2017.

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. 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.

Sempra Global

Line of Credit at September 30, 2015

Sempra Global had a $2.189 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. served as administrative agent for the syndicate of 25 lenders. Sempra Energy guaranteed Sempra Global’s obligations under the credit facility. Borrowings bore interest at benchmark rates plus a margin that varied with market index rates and Sempra Energy’s credit ratings. The facility required Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At September 30, 2015 and December 31, 2014, Sempra Energy was in compliance with this and all other financial covenants under the credit facility.

At September 30, 2015, Sempra Global had $734 million of commercial paper outstanding supported by the facility.

Amended and Restated Line of Credit Effective October 13, 2015

On October 13, 2015, Sempra Global entered into an amended and restated, five-year syndicated revolving credit agreement expiring in October 2020. The credit facility permits borrowings of up to $2.21 billion. Citibank, N.A. serves as administrative agent for the syndicate of 20 lenders and no single lender has greater than a 7-percent share. The credit facility amends, restates and supersedes Sempra Global’s $2.189 billion credit agreement that was to expire in 2017.

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.

California Utilities

Line of Credit at September 30, 2015

SDG&E and SoCalGas had a combined $877 million, five-year syndicated revolving credit agreement expiring in March 2017. JPMorgan Chase Bank, N.A. served as administrative agent for the syndicate of 24 lenders. The agreement permitted each utility to individually borrow up to $658 million, subject to a combined limit of $877 million for both utilities. It also provided for the issuance of letters of credit on behalf of each utility subject to a combined letter of credit commitment of $300 million for both utilities. The amount of borrowings otherwise available under the facility was reduced by the amount of outstanding letters of credit.

Borrowings under the facility bore interest at benchmark rates plus a margin that varied with market index rates and the borrowing utility’s credit ratings. The agreement required each utility to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At September 30, 2015 and December 31, 2014, the California Utilities were in compliance with this and all other financial covenants under the credit facility.

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

At September 30, 2015, SDG&E had $44 million of commercial paper outstanding, supported by the facility. SoCalGas had no outstanding borrowings supported by the facility. Available unused credit on the line at September 30, 2015 was $614 million and $658 million at SDG&E and SoCalGas, respectively, subject to the $877 million maximum combined credit limit.

Amended and Restated Line of Credit Effective October 13, 2015

On October 13, 2015, SDG&E and SoCalGas entered into a combined $1 billion, amended and restated, 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. The credit facility amends, restates and supersedes the California Utilities’ $877 million credit agreement that was to expire in 2017.

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.

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.

Sempra Mexico

In 2014, IEnova entered into an agreement for a $200 million, U.S. dollar-denominated, three-year corporate revolving credit facility with Banco Santander (México), S.A., Institución de Banca Múltiple, Grupo Financiero Santander México. Also in 2014, IEnova entered into an agreement for a $100 million, U.S. dollar-denominated, three-year corporate revolving credit facility with Sumitomo Mitsui Banking Corporation. Both revolving credit facilities were entered into to finance working capital and for general corporate purposes.

In August 2015, IEnova entered into a $400 million, five-year revolving credit agreement to replace, and repay the $210 million in outstanding borrowings under, the two existing revolving credit facilities described above. 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 September 30, 2015, IEnova had $290 million of outstanding borrowings supported by the facility, and available unused credit on the line was $110 million.

WEIGHTED AVERAGE INTEREST RATES

The weighted average interest rates on the total short-term debt at Sempra Energy Consolidated were 0.66 percent and 0.70 percent at September 30, 2015 and December 31, 2014, respectively. The weighted average interest rate on total short-term debt at SDG&E was 0.15 percent at September 30, 2015. At December 31, 2014, the weighted average interest rates on total short-term debt at SDG&E and SoCalGas were 0.27 percent and 0.25 percent, respectively.

LONG-TERM DEBT

Sempra Energy

In March 2015, Sempra Energy publicly offered and sold $500 million of 2.40-percent, fixed-rate notes maturing in 2020. Sempra Energy used the proceeds from this offering to repay outstanding commercial paper.

SDG&E

In March 2015, SDG&E publicly offered and sold $140 million of first mortgage bonds maturing in 2017 at a variable rate of three-month LIBOR plus 0.20 percent (0.53 percent at September 30, 2015) and $250 million of 1.914-percent amortizing first mortgage bonds maturing in 2022. SDG&E used the proceeds from the offering to repay outstanding commercial paper and for other general corporate purposes.

On August 28, 2015, SDG&E redeemed, prior to maturity, certain outstanding long-term debt instruments with a total principal amount of $169 million. The coupon rates of these instruments ranged from 4.9 percent to 5.5 percent, with maturities ranging from 2021 to 2027.

SoCalGas

In June 2015, SoCalGas publicly offered and sold $250 million of 1.55-percent and $350 million of 3.20-percent first mortgage bonds maturing in 2018 and 2025, respectively. SoCalGas used the proceeds from the offering to repay outstanding commercial paper and for other general corporate purposes.

Sempra South American Utilities

In May and June 2015, Luz del Sur borrowed $13 million and $22 million, respectively, under a bank loan facility. The loans accrue interest at 5.18 percent and mature in May 2018 and June 2018, respectively. In August 2015, Luz del Sur borrowed $9 million under a bank loan facility. The loan accrues interest at 6.70 percent and matures in February 2018. In September 2015, Luz del Sur publicly offered and sold $25 million of corporate bonds at 8.75 percent maturing in September 2026.

Sempra Natural Gas

In June 2015, Sempra Natural Gas reduced its other long-term debt by $79 million through redemption of its investment in industrial development bonds at Mississippi Hub, LLC. Sempra Natural Gas plans to redeem, prior to maturity, $55 million of industrial development bonds payable at Bay Gas Storage Company, Ltd. Accordingly, the debt is classified as current portion of long-term debt at September 30, 2015 on Sempra Energy’s Condensed Consolidated Balance Sheet. The redemption is anticipated to occur during the fourth quarter of 2015.

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 and benchmark interest rate risk. We may also manage foreign exchange rate exposures using derivatives. 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 presented below.

We record all 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.

In certain cases, we apply the normal purchase or sale exception to derivative accounting 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.

HEDGE ACCOUNTING

We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated 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 a given future 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 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 are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, 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 September 30, 2015 and December 31, 2014 as follows:

NET ENERGY DERIVATIVE VOLUMES

Segment and Commodity		September 30, 2015	December 31, 2014
California Utilities:
SDG&E:
Natural gas		59 million MMBtu	55 million MMBtu	(1)
Electricity		1 million MWh	―	(2)
Congestion revenue rights		24 million MWh	27 million MWh
SoCalGas – natural gas		1 million MMBtu	1 million MMBtu

Energy-Related Businesses:
Sempra Natural Gas – natural gas		39 million MMBtu	29 million MMBtu
(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 to moderate its exposure to interest rate changes. This activity was designated as a cash flow hedge as of April 1, 2011.

At September 30, 2015 and December 31, 2014, the net notional amounts of our interest rate derivatives, excluding the cross-currency swaps discussed below, were:

INTEREST RATE DERIVATIVES
(Dollars in millions)
		September 30, 2015			December 31, 2014
		Notional debt		Maturities	Notional debt		Maturities
Sempra Energy Consolidated:
Cash flow hedges(1)		$	389	2015-2028	$	399	2015-2028
Fair value hedges			300	2016		300	2016
SDG&E:
Cash flow hedge(1)			317	2015-2019		325	2015-2019
(1)	Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.

FOREIGN CURRENCY DERIVATIVES

We are exposed to exchange rate movements at our Mexican subsidiaries, which have U.S. dollar denominated cash balances, receivables and payables (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. These subsidiaries also have deferred income tax assets and liabilities that are denominated in the Mexican peso, which must be translated into U.S. dollars for financial reporting purposes. From time to time, we may utilize foreign currency derivatives at our subsidiaries and at the consolidated level as a means to manage the risk of exposure to significant fluctuations in our income tax expense from these impacts. We may also utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and joint ventures.

In addition, Sempra South American Utilities may utilize 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 September 30, 2015 and December 31, 2014, including the amount of cash collateral receivables that were not offset, as the cash collateral is in excess of liability positions.

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30, 2015
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and 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)		$	7	$	―	$	(16)	$	(159)
Commodity contracts not subject to rate recovery			6		―		―		―
Derivatives not designated as hedging instruments:
Interest rate and foreign exchange instruments			―		―		(3)		―
Commodity contracts not subject to rate recovery			166		31		(147)		(18)
Associated offsetting commodity contracts			(137)		(18)		137		18
Associated offsetting cash collateral			―		―		3		―
Commodity contracts subject to rate recovery			7		87		(59)		(65)
Associated offsetting commodity contracts			(1)		(1)		1		1
Associated offsetting cash collateral			―		―		25		28
Net amounts presented on the balance sheet			48		99		(59)		(195)
Additional cash collateral for commodity contracts
not subject to rate recovery			3		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			15		―		―		―
Total(4)		$	66	$	99	$	(59)	$	(195)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)		$	―	$	―	$	(15)	$	(29)
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			6		87		(59)		(65)
Associated offsetting commodity contracts			(1)		(1)		1		1
Associated offsetting cash collateral			―		―		25		28
Net amounts presented on the balance sheet			5		86		(48)		(65)
Additional cash collateral for commodity contracts
not subject to rate recovery			1		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			14		―		―		―
Total(4)		$	20	$	86	$	(48)	$	(65)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts not subject to rate recovery		$	―	$	―	$	(2)	$	―
Associated offsetting cash collateral			―		―		2		―
Commodity contracts subject to rate recovery			1		―		―		―
Net amounts presented on the balance sheet			1		―		―		―
Additional cash collateral for commodity contracts
not subject to rate recovery			1		―		―		―
Additional cash collateral for commodity contracts
subject to rate recovery			1		―		―		―
Total		$	3	$	―	$	―	$	―
(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, 2014
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and 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)		$	10	$	3	$	(17)	$	(109)
Commodity contracts not subject to rate recovery			25		―		―		―
Derivatives not designated as hedging instruments:
Interest rate instruments			8		27		(7)		(22)
Commodity contracts not subject to rate recovery			143		32		(135)		(29)
Associated offsetting commodity contracts			(129)		(27)		129		27
Associated offsetting cash collateral			(11)		―		―		―
Commodity contracts subject to rate recovery			36		76		(36)		(20)
Associated offsetting commodity contracts			(3)		(1)		3		1
Associated offsetting cash collateral			―		―		23		13
Net amounts presented on the balance sheet			79		110		(40)		(139)
Additional cash collateral for commodity contracts
subject to rate recovery			14		―		―		―
Total(4)		$	93	$	110	$	(40)	$	(139)
SDG&E:
Derivatives designated as hedging instruments:
Interest rate instruments(3)		$	―	$	―	$	(16)	$	(31)
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery			32		76		(32)		(20)
Associated offsetting commodity contracts			―		(1)		―		1
Associated offsetting cash collateral			―		―		23		13
Net amounts presented on the balance sheet			32		75		(25)		(37)
Additional cash collateral for commodity contracts
subject to rate recovery			12		―		―		―
Total(4)		$	44	$	75	$	(25)	$	(37)
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery		$	4	$	―	$	(4)	$	―
Associated offsetting commodity contracts			(3)		―		3		―
Net amounts presented on the balance sheet			1		―		(1)		―
Additional cash collateral for commodity contracts
subject to rate recovery			2		―		―		―
Total		$	3	$	―	$	(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 Other Comprehensive Income (Loss) (OCI) and Accumulated Other Comprehensive Income (Loss) (AOCI) for the three months and nine months ended September 30 were:

FAIR VALUE HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
			Pretax gain (loss) on derivatives recognized in earnings
			Three months ended September 30,				Nine months ended September 30,
		Location	2015		2014		2015		2014
Sempra Energy Consolidated:
Interest rate instruments		Interest Expense	$	1	$	1	$	5	$	6
Interest rate instruments		Other Income, Net		―		(1)		(2)		―
Total(1)			$	1	$	―	$	3	$	6
(1)	There was no hedge ineffectiveness on these swaps in either the three months or nine months ended September 30, 2015 and negligible gains and $9 million of gains from hedge ineffectiveness in the three months and nine months ended September 30, 2014, respectively. All other changes in the fair value of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and are recorded in Other Income, Net.

CASH FLOW HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
		Pretax gain (loss) recognized					Pretax gain (loss) reclassified from
		in OCI (effective portion)					AOCI into earnings (effective portion)
		Three months ended September 30,					Three months ended September 30,
		2015		2014		Location	2015		2014
Sempra Energy Consolidated:
Interest rate and foreign
exchange instruments(1)(2)		$	(10)	$	(5)	Interest Expense	$	(5)	$	(8)
						Gain on Sale of Equity Interests
Interest rate instruments			―		5	and Assets		―		5
						Equity Earnings,
Interest rate instruments			(134)		(4)	Before Income Tax		(3)		(2)
Commodity contracts not subject						Revenues: Energy-Related
to rate recovery			6		1	Businesses		3		2
Total(2)		$	(138)	$	(3)		$	(5)	$	(3)
SDG&E:
Interest rate instruments(1)(2)		$	(4)	$	1	Interest Expense	$	(3)	$	(3)

		Nine months ended September 30,					Nine months ended September 30,
		2015		2014		Location	2015		2014
Sempra Energy Consolidated:
Interest rate and foreign
exchange instruments(1)(2)		$	(22)	$	(15)	Interest Expense	$	(14)	$	(17)
						Gain on Sale of Equity Interests
Interest rate instruments			―		3	and Assets		―		3
						Equity Earnings,
Interest rate instruments			(123)		(34)	Before Income Tax		(9)		(7)
Commodity contracts not subject						Revenues: Energy-Related
to rate recovery			6		(5)	Businesses		10		(8)
Total(2)		$	(139)	$	(51)		$	(13)	$	(29)
SDG&E:
Interest rate instruments(1)(2)		$	(9)	$	(5)	Interest Expense	$	(9)	$	(8)
(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.
(2)	There were negligible losses from ineffectiveness related to these hedges in 2015 and 2014.

For Sempra Energy Consolidated, we expect that losses of $20 million, which are net of income tax benefit, that are currently recorded in AOCI (including $13 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, 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 term over which we are hedging exposure to the variability of cash flows at September 30, 2015 is approximately 13 years and 4 years for Sempra Energy Consolidated and SDG&E, respectively. The maximum term of hedged interest rate variability is 20 years, and is related to debt at Sempra Renewables’ equity method investees.

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

UNDESIGNATED DERIVATIVE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
		Pretax gain (loss) on derivatives recognized in earnings
		Three months ended September 30,				Nine months ended September 30,
	Location	2015		2014		2015		2014
Sempra Energy Consolidated:
Interest rate and foreign exchange
instruments	Other Income, Net	$	(4)	$	(6)	$	(7)	$	(6)
Foreign exchange instruments	Equity Earnings,
	Net of Income Tax		(3)		(2)		(4)		(4)
Commodity contracts not subject	Revenues: Energy-Related
to rate recovery	Businesses		21		3		33		2
Commodity contracts not subject	Cost of Natural Gas, Electric Fuel
to rate recovery	and Purchased Power		―		1		―		3
Commodity contracts not subject
to rate recovery	Operation and Maintenance		(2)		―		(1)		―
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power		(27)		(1)		(100)		19
Commodity contracts subject
to rate recovery	Cost of Natural Gas		―		1		1		2
Total		$	(15)	$	(4)	$	(78)	$	16
SDG&E:
Commodity contracts not subject
to rate recovery	Operation and Maintenance	$	(1)	$	―	$	(1)	$	―
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power		(27)		(1)		(100)		19
Total		$	(28)	$	(1)	$	(101)	$	19
SoCalGas:
Commodity contracts not subject
to rate recovery	Operation and Maintenance	$	(1)	$	―	$	―	$	―
Commodity contracts subject
to rate recovery	Cost of Natural Gas		―		1		1		2
Total		$	(1)	$	1	$	1	$	2

CONTINGENT FEATURES

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

For Sempra Energy Consolidated, the total fair value of this group of derivative instruments in a net liability position at September 30, 2015 and December 31, 2014 is $8 million and $9 million, respectively. At September 30, 2015, if the credit ratings of Sempra Energy were reduced below investment grade, $8 million of additional assets could be required to be posted as collateral for these derivative contracts.

For SDG&E, the total fair value of this group of derivative instruments in a net liability position was $5 million and $2 million at September 30, 2015 and December 31, 2014, respectively. At September 30, 2015, if the credit ratings of SDG&E were reduced below investment grade, $5 million of additional assets could be required to be posted as collateral for these derivative contracts.

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

NOTE 8. FAIR VALUE MEASUREMENTS

We discuss the valuation techniques and inputs we use to measure fair value and the definition of the three levels of the fair value hierarchy in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We have not changed the valuation techniques or inputs we use to measure fair value during the nine months ended September 30, 2015.

Recurring Fair Value Measures

The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at September 30, 2015 and December 31, 2014. 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 September 30, 2015 and December 31, 2014 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).

We enter into commodity contracts and interest rate derivatives primarily as a means to manage price exposures. We may also manage foreign exchange rate exposures using derivatives. 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.” We record commodity derivative contracts that are subject to rate recovery as commodity costs that are offset by regulatory account balances and are recovered in rates.

§	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).

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, nor any changes in valuation techniques used in recurring fair value measurements.

RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		Fair value at September 30, 2015
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	588	$	―	$	―	$	―	$	588
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			51		44		―		―		95
Municipal bonds			―		154		―		―		154
Other securities			―		205		―		―		205
Total debt securities			51		403		―		―		454
Total nuclear decommissioning trusts(2)			639		403		―		―		1,042
Interest rate and foreign exchange instruments			―		7		―		―		7
Commodity contracts not subject to rate recovery			31		17		―		3		51
Commodity contracts subject to rate recovery			―		1		91		15		107
Total		$	670	$	428	$	91	$	18	$	1,207
Liabilities:
Interest rate and foreign exchange instruments		$	―	$	178	$	―	$	―	$	178
Commodity contracts not subject to rate recovery			8		2		―		(3)		7
Commodity contracts subject to rate recovery			―		67		55		(53)		69
Total		$	8	$	247	$	55	$	(56)	$	254

		Fair value at December 31, 2014
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	655	$	―	$	―	$	―	$	655
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			62		47		―		―		109
Municipal bonds			―		129		―		―		129
Other securities			―		207		―		―		207
Total debt securities			62		383		―		―		445
Total nuclear decommissioning trusts(2)			717		383		―		―		1,100
Interest rate and foreign exchange instruments			―		48		―		―		48
Commodity contracts not subject to rate recovery			28		16		―		(11)		33
Commodity contracts subject to rate recovery			―		1		107		14		122
Total		$	745	$	448	$	107	$	3	$	1,303
Liabilities:
Interest rate and foreign exchange instruments		$	―	$	155	$	―	$	―	$	155
Commodity contracts not subject to rate recovery			3		9		―		(4)		8
Commodity contracts subject to rate recovery			―		52		―		(36)		16
Total		$	3	$	216	$	―	$	(40)	$	179
(1)	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(2)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
		Fair value at September 30, 2015
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	588	$	―	$	―	$	―	$	588
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			51		44		―		―		95
Municipal bonds			―		154		―		―		154
Other securities			―		205		―		―		205
Total debt securities			51		403		―		―		454
Total nuclear decommissioning trusts(2)			639		403		―		―		1,042
Commodity contracts not subject to rate recovery			―		―		―		1		1
Commodity contracts subject to rate recovery			―		―		91		14		105
Total		$	639	$	403	$	91	$	15	$	1,148
Liabilities:
Interest rate instruments		$	―	$	44	$	―	$	―	$	44
Commodity contracts not subject to rate recovery			1		―		―		(1)		―
Commodity contracts subject to rate recovery			―		67		55		(53)		69
Total		$	1	$	111	$	55	$	(54)	$	113

		Fair value at December 31, 2014
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	655	$	―	$	―	$	―	$	655
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			62		47		―		―		109
Municipal bonds			―		129		―		―		129
Other securities			―		207		―		―		207
Total debt securities			62		383		―		―		445
Total nuclear decommissioning trusts(2)			717		383		―		―		1,100
Commodity contracts subject to rate recovery			―		―		107		12		119
Total		$	717	$	383	$	107	$	12	$	1,219
Liabilities:
Interest rate instruments		$	―	$	47	$	―	$	―	$	47
Commodity contracts not subject to rate recovery			1		―		―		(1)		―
Commodity contracts subject to rate recovery			―		51		―		(36)		15
Total		$	1	$	98	$	―	$	(37)	$	62
(1)	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(2)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
		Fair value at September 30, 2015
			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		―		1		2
Total		$	―	$	1	$	―	$	2	$	3
Liabilities:
Commodity contracts not subject to rate recovery		$	2	$	―	$	―	$	(2)	$	―
Total		$	2	$	―	$	―	$	(2)	$	―

		Fair value at December 31, 2014
			Level 1		Level 2		Level 3		Netting(1)		Total
Assets:
Commodity contracts subject to rate recovery		$	―	$	1	$	―	$	2	$	3
Total		$	―	$	1	$	―	$	2	$	3
Liabilities:
Commodity contracts not subject to rate recovery		$	2	$	―	$	―	$	(2)	$	―
Commodity contracts subject to rate recovery			―		1		―		―		1
Total		$	2	$	1	$	―	$	(2)	$	1
(1)	Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.

Level 3 Information

The following table sets forth reconciliations of changes in the fair value of Congestion Revenue Rights (CRRs) and long-term, fixed-price electricity positions classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E:

LEVEL 3 RECONCILIATIONS
(Dollars in millions)
	Three months ended September 30,
	2015		2014
Balance as of July 1	$	42	$	85
Realized and unrealized (losses) gains		(49)		3
Allocated transmission instruments		―		9
Settlements		43		(10)
Balance as of September 30	$	36	$	87
Change in unrealized gains or losses relating to
instruments still held at September 30	$	(8)	$	―

	Nine months ended September 30,
	2015		2014
Balance as of January 1	$	107	$	99
Realized and unrealized (losses) gains		(103)		9
Allocated transmission instruments		1		10
Settlements		31		(31)
Balance as of September 30	$	36	$	87
Change in unrealized gains or losses relating to
instruments still held at September 30	$	(54)	$	―

SDG&E’s Energy and Fuel Procurement department, in conjunction with SDG&E’s finance group, is responsible for determining the appropriate fair value methodologies used to value and classify CRRs and long-term, fixed-price electricity positions on an ongoing basis. Inputs used to determine the fair value of CRRs and fixed-priced 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 calendar year. The impact associated with discounting is negligible. Because auction prices are a less observable input, these instruments are classified as Level 3. From January 1, 2015 to December 31, 2015, the auction prices range from $(16) per MWh to $8 per MWh at a given location, and from January 1, 2014 to December 31, 2014, the auction prices ranged from $(6) per MWh to $12 per MWh at a given location. The fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 7.

Long-term 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 that range from $24.15 per MWh to $60.01 per MWh. A significant increase or decrease in market electricity forward prices would result in a significantly higher or lower fair value, respectively.

Realized gains and losses associated with CRRs and long-term electricity positions are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, 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, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts. 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 at September 30, 2015 and December 31, 2014:

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
		September 30, 2015
		Carrying		Fair value
		amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Total long-term debt(1)(2)		$	13,341	$	―	$	13,693	$	703	$	14,396
Preferred stock of subsidiary			20		―		22		―		22
SDG&E:
Total long-term debt(2)(3)		$	4,557	$	―	$	4,652	$	317	$	4,969
SoCalGas:
Total long-term debt(4)		$	2,512	$	―	$	2,658	$	―	$	2,658
Preferred stock			22		―		24		―		24

		December 31, 2014
		Carrying		Fair value
		amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Total long-term debt(1)(2)		$	12,347	$	―	$	12,782	$	917	$	13,699
Preferred stock of subsidiary			20		―		23		―		23
SDG&E:
Total long-term debt(2)(3)		$	4,461	$	―	$	4,563	$	425	$	4,988
SoCalGas:
Total long-term debt(4)		$	1,913	$	―	$	2,124	$	―	$	2,124
Preferred stock			22		―		25		―		25
(1)	Before reductions for unamortized discount (net of premium) of $21 million at both September 30, 2015 and December 31, 2014, and excluding build-to-suit and capital lease obligations of $375 million and $310 million at September 30, 2015 and December 31, 2014, 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.
(2)	Level 3 instruments include $317 million and $325 million at September 30, 2015 and December 31, 2014, respectively, related to Otay Mesa VIE.
(3)	Before reductions for unamortized discount of $10 million and $11 million at September 30, 2015 and December 31, 2014, respectively, and excluding capital lease obligations of $231 million and $234 million at September 30, 2015 and December 31, 2014, respectively.
(4)	Before reductions for unamortized discount of $7 million and $8 million at September 30, 2015 and December 31, 2014, respectively, and excluding capital lease obligations of $2 million and $1 million at September 30, 2015 and December 31, 2014, respectively.

We base the fair value of certain 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 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 SONGS in Note 9 below.

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, 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 Outage and Retirement

Background

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. In March 2012, in response to the shutdown of SONGS, the NRC issued a Confirmatory Action Letter (CAL) which, among other things, outlined the requirements for Edison to meet before the NRC would approve a restart of either of the Units.

In October 2012, Edison submitted a restart plan to the NRC proposing to operate Unit 2 at a reduced power level for a period of five months, at which time the Unit would be brought down for further inspection. Edison did not file a restart plan for Unit 3, pending further inspection and analysis of what repairs or modifications would be required to return the Unit to service in a safe manner. The NRC was reviewing the restart plan for Unit 2 proposed by Edison when in May 2013, the Atomic Safety and Licensing Board (ASLB), an adjudicatory arm of the NRC, concluded that the CAL process constituted a de facto license amendment proceeding that was subject to a public hearing. This conclusion by the ASLB resulted in further uncertainty regarding when a final decision might be made on restarting Unit 2.

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 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)

SONGS OII

In November 2012, in response to the outage, the CPUC issued the SONGS OII, pursuant to California Public Utilities’ Code Section 455.5, which applies to cost recovery issues resulting from long-term outages of operating assets. The SONGS OII consolidated most SONGS outage-related issues into a single proceeding. The SONGS OII, among other things, designated all revenues associated with the investment in, and operation of, SONGS since January 1, 2012 as subject to refund to customers, pending the outcome of all phases of the proceeding. The SONGS OII proceeding 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).

Entry Into Settlement Agreement

Pursuant to CPUC rules concerning settlements, SDG&E, Edison, The Utility Reform Network (TURN), and the CPUC Office of Ratepayer Advocates (ORA) held a settlement conference in March 2014 to discuss the terms to resolve the SONGS OII, and in April 2014, SDG&E, along with Edison, TURN, the ORA and two other intervenors who joined the Settlement Agreement to the SONGS OII proceeding (collectively, the Settling Parties), filed a Settlement Agreement with the CPUC. On September 5, 2014, the CPUC issued a ruling proposing specific changes that included, as they relate to SDG&E, greater ratepayer benefit from third party cost recoveries and funding of a research program to reduce greenhouse gas emissions at a shareholder cost of $1 million per year for 5 years.

On September 23, 2014, the Settling Parties executed an Amended and Restated Settlement Agreement (Amended Settlement Agreement), which amended the Settlement Agreement to adopt all of the modifications and clarifications requested in the CPUC ruling. On October 9, 2014, the CPUC issued a proposed decision approving the Amended Settlement Agreement, which was adopted by the CPUC as a final decision on November 20, 2014.

As approved by the CPUC, the Amended Settlement Agreement constitutes a complete and final resolution of the SONGS OII and related CPUC proceedings regarding the SGRP at SONGS and the related outage and subsequent shutdown of SONGS. This resolution also required the compliance filing referenced below under “Accounting and Financial Impacts.” 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.

In November 2014, in accordance with the Amended Settlement Agreement, SDG&E filed an advice letter seeking authority from the CPUC, among other things, to implement the terms and establish the revenue requirement in accordance with the Amended Settlement Agreement in rates starting January 1, 2015. In December 2014, the CPUC approved the advice letter and authorized SDG&E to update rates accordingly, subject to revision pending the results of a CPUC review of the changes to the revenue requirement proposed by SDG&E for consistency with the terms of the approved settlement decision. In March 2015, SDG&E received a final disposition letter from the CPUC confirming that SDG&E’s proposed rate changes were in compliance with the approved settlement decision.

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.

We discuss the terms of the Amended Settlement Agreement in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

Accounting and Financial Impacts

Through September 30, 2015, the cumulative after-tax loss from plant closure recorded by Sempra Energy and SDG&E is $127 million, including a reduction in the after-tax loss of $13 million recorded 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.

In the second quarter of 2013, based on an initial assessment of the financial impact of the outcome of the SONGS OII proceeding, SDG&E reported an after-tax loss from plant closure of $119 million. In the first quarter of 2014, after entering into the Settlement Agreement, SDG&E recorded a $9 million increase in the after-tax loss. In the fourth quarter of 2014, based on the compliance filing regarding SDG&E’s annual revenue requirement and the timing of refunds to ratepayers, SDG&E recorded a $12 million increase to the after-tax loss.

The regulatory asset for the expected recovery of SONGS costs, consistent with the Amended Settlement Agreement, is $272 million ($42 million current and $230 million long-term) at September 30, 2015 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.

Settlement with Nuclear Electric Insurance Limited (NEIL)

As we discuss in Note 11, 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 approximately $80 million. Pursuant to the terms of the SONGS OII Amended Settlement Agreement, the recovery will be allocated 95 percent to SDG&E’s customers, through ERRA, and 5 percent to SDG&E, after reimbursement of the costs incurred in pursuing the claims. SDG&E will record the recoveries from NEIL during the fourth quarter of 2015.

NRC Proceedings

In December 2013, Edison received a final NRC Inspection Report that identified a violation for the failure to verify the adequacy of the thermal-hydraulic and flow-induced vibration design of the Unit 3 replacement steam generator. In January 2014, Edison provided a response to the NRC Inspection Report stating that MHI, as contracted by Edison to prepare the SONGS replacement steam generator design, was the party responsible for validating the design of the steam generators.

In addition, the NRC issued an Inspection Report to MHI containing a Notice of Nonconformance for its flawed computer modeling in the design of the replacement steam generators.

Because SONGS has ceased operation, NRC inspection oversight of SONGS will now be continued through the NRC’s Decommissioning Power Reactor Inspection Program to verify that decommissioning activities are being conducted safely, that spent fuel is safely stored onsite or transferred to another licensed location, and that the site operations and licensee termination activities conform to applicable regulatory requirements, licensee commitments and management controls.

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 in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

In accordance with state and federal requirements and regulations, SDG&E has assets held in trusts, referred to as the Nuclear Decommissioning Trusts (NDT), to fund decommissioning costs for SONGS Units 1, 2 and 3. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work will be done when Units 2 and 3 are decommissioned. At September 30, 2015, 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 February 2014, SDG&E filed a request with the CPUC for such authorization for costs incurred in 2013. In April 2015, SDG&E withdrew its pending request and filed a new request based on updated decommissioning cost information, seeking authorization to access trust funds for up to $55 million in decommissioning costs incurred in 2013. The CPUC authorized the request in July 2015. In August 2015, SDG&E withdrew $37 million of the authorized amount, $34 million of which will be funded to customers through the ERRA balancing account. Another $3 million of the amount withdrawn was used to refund regulatory assets and certain costs pursuant to the SONGS OII Settlement Agreement. The remaining $18 million of the CPUC authorization 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 October 2015, SDG&E filed a request with the CPUC seeking authorization to access trust funds for $36 million for SONGS Units 2 and 3 decommissioning costs incurred in 2014. If the Commission approves the request, SDG&E intends to withdraw $23 million, which will be funded to customers through the ERRA balancing account or used to refund regulatory assets and certain costs pursuant to the SONGS OII Settlement Agreement. The remaining $13 million will be withdrawn pending satisfactory clarification by the IRS, as discussed above.

SDG&E will continue to use working capital to pay for any SONGS Units 2 and 3 decommissioning costs incurred, and file periodic requests with the CPUC seeking authorization to access funds for reimbursement from the NDT for incurred decommissioning costs.

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:

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
					Gross		Gross		Estimated
					unrealized		unrealized		fair
			Cost		gains		losses		value
At September 30, 2015:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies(1)		$	90	$	5	$	―	$	95
Municipal bonds(2)			147		7		―		154
Other securities(2)			214		3		(12)		205
Total debt securities			451		15		(12)		454
Equity securities			212		382		(6)		588
Cash and cash equivalents			18		―		―		18
Total		$	681	$	397	$	(18)	$	1,060
At December 31, 2014:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		$	103	$	6	$	―	$	109
Municipal bonds			121		8		―		129
Other securities			206		7		(6)		207
Total debt securities			430		21		(6)		445
Equity securities			215		444		(4)		655
Cash and cash equivalents			30		1		―		31
Total		$	675	$	466	$	(10)	$	1,131
(1)	Maturity dates are 2016-2065.
(2)	Maturity dates are 2015-2115.

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

SALES OF SECURITIES
(Dollars in millions)
		Three months ended September 30,				Nine months ended September 30,
		2015		2014		2015		2014
Proceeds from sales(1)		$	210	$	148	$	431	$	498
Gross realized gains			18		5		24		9
Gross realized losses			(6)		(3)		(13)		(8)
(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 prospectively set rates sufficient 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 February 2015, the CPUC issued a scoping memo setting the schedule for the proceeding, including the issuance of a proposed decision by the end of 2015. In March 2015, the California Utilities revised their requests to make various updates and reflect the impact of the Tax Increase Prevention Act signed into law in December 2014. At SoCalGas, this resulted in a reduction of $10 million compared to its original request, or a total revenue requirement in 2016 of $2.342 billion. This is an increase of $246 million or 12 percent over 2015, excluding the impact of the 2015 revenue requirement increase discussed below under “SoCalGas Matters — Increase to CPUC-Authorized Annual Revenue Requirement.” At SDG&E, the March 2015 revised request resulted in a reduction of $6 million compared to its original request, or a total revenue requirement in 2016 of $1.905 billion. This is an increase of $111 million or 6 percent over 2015. This increase includes an adjustment of $16 million to the comparable 2015 estimated revenue requirement since the November 2014 filings.

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 deductions, discussed below. The settlement agreements are with eight of eleven intervening parties. For SoCalGas, the settlement proposes a reduction of $133 million compared to its original request, or a total revenue requirement in 2016 of $2.219 billion. This is an increase of $122 million or 6 percent over 2015. For SDG&E, the settlement proposes a reduction of $100 million compared to its original request (as revised), or a total revenue requirement in 2016 of $1.811 billion. This is an increase of $17 million, or one percent over 2015. The filed settlement agreements also call for attrition adjustments of 3.5 percent for both 2017 and 2018. 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.

The settlement agreements described above exclude a proposal that, for both SDG&E and SoCalGas, certain intra-rate case income tax benefits should be, in effect, refunded and passed to ratepayers. 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. The proposal recommends that the CPUC adjust SDG&E’s rate base by $93 million and SoCalGas’ rate base by $92 million, and additionally reduce both utilities’ revenue requirements by amounts currently being tracked in tax memorandum accounts for the year 2015. At September 30, 2015, the pretax balances tracked in these memorandum accounts total $46 million for SoCalGas and $34 million for SDG&E. If this proposal is adopted, the outcome would reduce the revenue requirement amounts agreed to in the respective settlement agreements described above.

We anticipate all matters to be resolved with the final resolution of the 2016 GRC. We expect the CPUC to issue a draft decision in the proceeding in the first quarter of 2016.

Natural Gas Pipeline Operations Safety Assessments

In June 2014, the CPUC issued a final decision in the Triennial Cost Allocation Proceeding (TCAP) 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 the 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.

In October 2014, SDG&E and SoCalGas filed a petition for modification 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. In August 2015, the ORA, TURN and the Southern California Generation Coalition (SCGC) served testimony to the CPUC that recommended disallowances related to completed projects, as well as facilities build-out costs, de-scoped projects, and project management and consulting costs. The ORA’s recommended disallowance would result in an $11.1 million decrease to SoCalGas’ original recovery application of $26.8 million, to $15.7 million. The disallowance recommended by TURN and SCGC would result in a $2.3 million decrease to SoCalGas’ original recovery application of $26.8 million, to $24.5 million. In August 2015, the California Utilities also provided testimony to the CPUC, contesting the proposed disallowances. 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. The ORA and TURN alleged 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 November 2014, the CPUC denied the ORA and TURN request for rehearing of the decision adopting the PSEP. In December 2014, the ORA and TURN sought rehearing of the CPUC’s decision on rehearing. In late December 2014, SoCalGas and SDG&E filed their opposition to this second application for rehearing, and are continuing to implement PSEP in accordance with the June 2014 CPUC decision. In March 2015, the CPUC issued a decision denying the ORA’s and TURN’s second request for rehearing, but keeping the record in the proceeding open to admit additional evidence on the limited issue of pressure testing of pipelines installed between January 1, 1956 and July 1, 1961. As part of this review, the CPUC will allow parties to submit additional evidence relevant to this narrow issue to ensure a complete record, with no additional discovery allowed. The ORA and TURN filed their responses on May 1, 2015. In October 2015, the CPUC issued a proposed 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 pipeline. At September 30, 2015, SoCalGas and SDG&E estimate amounts related to these costs to be approximately $5 million and $3 million, respectively.

Southern Gas System Reliability Project

In December 2013, SoCalGas and SDG&E filed a joint application with the CPUC seeking authority to recover the full cost of the Southern Gas System Reliability Project. Also known as the North-South Gas Project, the project will enhance reliability on the southern portions of the California Utilities’ integrated natural gas transmission system (Southern System). The estimated cost of the project, as originally filed, is between $800 million to $850 million. As originally proposed, the project consisted of three components: 1) constructing an approximately 60-mile, 36-inch natural gas transmission pipeline between the SoCalGas Adelanto compressor station and the Moreno pressure limiting station; 2) upgrading the Adelanto compressor station; and 3) constructing an approximately 31-mile, 36-inch pipeline from the Moreno pressure limiting station to a pressure limiting station in Whitewater. In November 2014, the California Utilities revised the scope of the proposed project to only include connecting the Adelanto compressor station and Moreno pressure limiting station with approximately 65 miles of 36-inch pipeline and upgrading the Adelanto compressor station, and eliminating the Moreno-Whitewater pipeline. In March 2015, the CPUC issued a revised scoping ruling establishing a schedule, directing that the Moreno-Whitewater portion of the original project be excluded from scope and that any other future projects would be addressed separately. The estimated cost of the revised project, including updated cost estimates, remains unchanged from the original cost estimate of between $800 million and $850 million, while providing comparable benefits for customers. If approved by the CPUC and subject to environmental permitting, given the revised project scope and updated schedule in this proceeding, the project could commence construction in 2017 and be in service by the end of 2019.

Pipeline Safety & Reliability Project

In September 2015, SDG&E and SoCalGas filed an application with the CPUC seeking authority to recover the full cost of the Pipeline Safety & Reliability Project. The project involves construction of an approximately 47-mile, 36-inch natural gas transmission pipeline in San Diego County from SDG&E’s existing Rainbow Metering Station near the Riverside County line to Marine Corps Air Station (MCAS) Miramar. We estimate the project costs to be $600 million and that it will take approximately 24 to 36 months to construct after CPUC approval is received, depending on the timing of other approvals. The new pipeline will implement pipeline safety requirements and modernize the system; improve system reliability and resiliency by minimizing dependence on a single pipeline; and enhance operational flexibility to manage stress conditions by increasing system capacity. The project is a part of the PSEP work described above. The final resolution of this project will help define the scope of work to be completed under PSEP.

Utility Incentive Mechanisms

The CPUC applies performance-based measures and incentive mechanisms to all California investor-owned utilities, under which the California Utilities have earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals.

Natural Gas Procurement

In February 2015, the CPUC issued a final decision approving SoCalGas’ application for a gas cost incentive mechanism (GCIM) award of $13.7 million for natural gas procured for its core customers during the 12-month period ended March 31, 2014. SoCalGas recorded this award in the first quarter of 2015.

In June 2015, SoCalGas filed an application for a GCIM award of $7.25 million for natural gas procured for its core customers during the 12-month period ended March 31, 2015. We expect a CPUC decision in the first half of 2016.

Energy Efficiency Programs

In September 2015, the CPUC issued a decision granting two rehearing requests filed by the ORA and TURN regarding the utility incentive awards for SDG&E and SoCalGas, as well as Edison and Pacific Gas and Electric Company, for program years 2006 through 2008, which totaled $16.2 million for SDG&E and $17.3 million for SoCalGas. The decision directs that the rehearing ensure that the incentive awards granted were just and reasonable and based on calculations verified by the CPUC, or otherwise refunded to customers.

SDG&E MATTERS

SONGS

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

2007 Wildfire 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). In a prior decision, the CPUC granted SDG&E authority to record its costs associated with the October 2007 wildfires in the WEMA and to seek rate recovery subject to a reasonableness review of the costs. 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.

We provide additional information about 2007 wildfire litigation costs and their recovery in Note 11.

Power Procurement and Resource Planning

Cleveland National Forest Transmission Projects

SDG&E filed an application with the CPUC in October 2012 for a permit to construct various transmission line replacement projects in and around the Cleveland National Forest (CNF). The proposed projects will replace and fire-harden five existing transmission lines at an estimated cost of between $400 million and $450 million, as originally proposed. As directed by the CPUC, SDG&E filed an amended application in June 2013 to provide notice of certain alternatives proposed by the United States Forest Service (USFS) in connection with SDG&E’s request for a Master Special Use Permit (MSUP). USFS approval of the MSUP will establish land rights and conditions for SDG&E’s continued operation and maintenance of facilities located within the CNF. CPUC approval is not required for the MSUP, even though construction of the projects is subject to review by both the USFS and CPUC. A final environmental impact report (EIR/EIS), developed jointly by the CPUC and USFS, was issued in July 2015 identifying alternatives to the proposed project which, if approved by both the CPUC and USFS, would result in an increase to the estimated cost of the projects. SDG&E currently expects separate USFS and CPUC decisions on the transmission projects in the first half of 2016 and then expects the various phases of this project to be placed in service starting in 2016 and continuing through the end of the project in 2019.

Sycamore-Peñasquitos Transmission Project

In March 2014, the CAISO selected SDG&E, as a result of a competitive bid process, to construct the Sycamore-Peñasquitos 230-kilovolt (kV) transmission project, which will provide a 16.7-mile transmission connection between SDG&E’s Sycamore Canyon and Peñasquitos substations. In July 2014, the CPUC notified SDG&E that the application requesting a Certificate of Public Convenience and Necessity (CPCN) to construct the line, which was filed with the CPUC in April 2014, is complete. The estimated $120 million to $150 million project, as originally proposed, was identified by the CAISO and a state task force as necessary to ensure grid reliability given the closure of SONGS. The project will also serve to strengthen renewable energy infrastructure in the region. In October 2014, SDG&E filed a request with FERC seeking, among other things, a 100 basis point return on equity (ROE) adder for this project. In April 2015, FERC issued an order granting SDG&E’s request for 100 percent abandoned plant cost recovery, but denying an ROE adder for the project. In September 2015, a draft environmental report was issued recommending an environmentally superior alternative that would underground more of the project than originally proposed. SDG&E estimates that the cost of the recommended alternative is $250 million to $300 million. SDG&E expects a CPUC decision on the project in the first half of 2016, with the line expected to be in service in mid-2017.

South Orange County Reliability Enhancement

SDG&E filed an application with the CPUC in May 2012 requesting a CPCN for the South Orange County Reliability Enhancement project. A draft environmental report was issued in the first quarter of 2015. In August 2015, portions of the draft environmental report were recirculated for public comment on additional project alternatives. SDG&E expects a final CPUC decision on the estimated $350 million to $400 million project in the first half of 2016. As the project is planned in phases, SDG&E currently expects the entire project to be in service in 2020.

Electric Vehicle Charging Program

In April 2014, SDG&E filed a proposal with the CPUC requesting approval of a program under which SDG&E would build and own a total of 5,500 electric vehicle charging stations at an estimated cost of $103 million, of which $59 million is capital investment. Under the program, SDG&E will provide an hourly Vehicle-to-Grid Integration (VGI) rate that will help incent participants to charge their vehicles during times of the day that benefit the power grid. In June 2015, SDG&E and sixteen other parties representing the electric vehicle charging industry, auto manufacturers, labor, and environmental and social justice organizations filed a settlement agreement proposing a modified program that still allows SDG&E to build and own a total of 5,500 charging stations. The settlement is opposed by certain consumer advocates and other parties. SDG&E expects a CPUC decision in the fourth quarter of 2015.

Distribution Resource Plan

In July 2015, SDG&E filed an application with the CPUC submitting its Distribution Resource Plan. Distributed energy resources (DER) are typically smaller power sources, including advanced renewable and energy storage technologies, that are connected to the distribution grid and located near load centers. The distribution resource plan sets out a planning and investment framework comprised of three basic categories: 1) capital investments that can be potentially deferred or replaced by DER solutions; 2) capital investment needed to accommodate higher DER deployment levels; and 3) traditional distribution investments that cannot be deferred or displaced by DER. SDG&E’s planning framework would be used to determine future capital investment needs, which would then be addressed through its GRC process. The Distribution Resource Plan also proposes a number of demonstration projects and describes potential projects and investment that would support higher DER deployment. SDG&E expects a CPUC decision in the first half of 2016.

Sunrise Powerlink Electric Transmission Line

In August 2015, SDG&E filed a petition with the CPUC requesting that it revise and confirm the project cost cap for the Sunrise Powerlink, a 500-kV electric transmission line between the Imperial Valley and the San Diego region that was energized and placed in service in June 2012. While post-energization construction activities for the project were completed in 2013, certain matters relating to outstanding claims were not resolved until the first quarter of 2015. The filing requests CPUC approval of the final expenditure report for the project and the proposed revisions to the total project cost cap. As evidenced in the final report, and summarized in the table below, actual expenditures for the project totaled $1,887.4 million (in 2012 dollars, on a net present value basis), which exceeds the total project cost cap approved by the CPUC in 2008 (CPUC Approval Decision) by $4.4 million.

SUNRISE POWERLINK ELECTRIC TRANSMISSION LINE – PROPOSED REVISIONS TO TOTAL PROJECT COST CAP
(Dollars in millions)
							Total
	Construction costs		Undergrounding on		Mitigation		(2012 dollars, net
	and AFUDC		Alpine Blvd.		and monitoring costs		present value basis)
Final status report	$	1,490.9	$	11.7	$	384.8	$	1,887.4
2008 CPUC approval decision		1,594.2		91.0		197.8		1,883.0
Difference	$	(103.3)	$	(79.3)	$	187.0	$	4.4

Subsequent to the required approvals of the U.S. Department of Interior, Bureau of Land Management (BLM) in January 2009 and the USFS in July 2010, which formed the basis of the CPUC Approval Decision summarized above, the CPUC’s Energy Division and the federal agencies published the Sunrise Final Mitigation Monitoring, Compliance, and Reporting Program (MMCRP). The MMCRP increased the amount of required mitigation activities and costs by $187 million. Off-setting this cost, in part, was a reduction in the total mileage of undergrounding on Alpine Boulevard by approximately two miles. The terms of the CPUC Approval Decision contemplate the potential reduction in undergrounding mileage at an estimated $11 million per one quarter mile. The CPUC Approval Decision did not anticipate the changes in monitoring and mitigation costs. In its petition, SDG&E proposes that the applicable total cost cap be revised and confirmed at the amount of $1,887.4 billion. This amount will be the basis used in SDG&E’s FERC-regulated transmission rates. SDG&E expects a CPUC decision on the petition in 2016.

SOCALGAS MATTERS

Triennial Cost Allocation Proceeding (TCAP) – Adoption of Seasonal Factors

The TCAP decision issued by the CPUC in June 2014 for SoCalGas included, among other matters, the requirement for SoCalGas to apply seasonal factors throughout the year to SoCalGas’ annual authorized revenue for its core natural gas customers effective January 1, 2015. Core customers are primarily residential and small commercial and industrial customers. The seasonal factors adopted are based on the core demand forecast provided by SoCalGas in the TCAP application. Prior to this decision, this annual authorized revenue was recognized ratably over the year. While this “seasonalization” will not impact SoCalGas’ total calendar year revenue or earnings for 2015 or beyond, and does not change the annual total authorized revenue or our earnings from that revenue, it will cause variability in revenue and earnings from quarter to quarter. We expect that as a result of applying the seasonal factors during interim periods to the annual authorized revenue requirement, the core natural gas customer authorized revenue recognized in the first and fourth quarters of each year beginning with 2015 will be higher (approximately 34 percent in the first quarter and 29 percent in the fourth quarter) than that recognized in the second and third quarters of each year (approximately 21 percent in the second quarter and 16 percent in the third quarter). This compares to recognizing 25 percent of the annual authorized revenue in each quarter in prior years. As a result, beginning in 2015, substantially all of SoCalGas’ annual earnings will be recognized in the first and fourth quarters of the year.

Seasonalization will not impact interim period cash flows or customers’ bills. However, it should reduce the interim period variability in regulatory balancing accounts, as we expect customer billings to more closely align with interim period revenue recognition. This seasonalization is consistent with SDG&E’s natural gas and power distribution authorized revenue treatment.

The CPUC regulatory framework authorizes SoCalGas to recover the actual cost of natural gas procured and delivered to its core customers in rates substantially as incurred. The regulatory framework also permits SoCalGas to recover its cost of operations, including depreciation of its fixed assets, in authorized revenue based on estimated annual natural gas demand forecasts approved in the TCAP, and any difference between actual gas demand and the annual natural gas demand approved in the TCAP is recovered in authorized revenue in the subsequent year. This design, commonly known as “decoupling,” is intended to minimize any impact on SoCalGas’ earnings of changes in the cost of natural gas procured and any variability in customer demand for natural gas. The adoption of applying seasonal factors to authorized annual revenue requirement for interim periods does not change the application of decoupling.

Increase to CPUC-Authorized Annual Revenue Requirement

In July 2011, SoCalGas updated its testimony in the 2012 GRC to reflect the impact of the extension of temporary bonus depreciation by the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Act). The 2010 Tax Act’s extension of bonus depreciation for U.S. federal income tax purposes for years 2010 through 2012 resulted in significant additional tax depreciation deductions. These additional deductions generated U.S. federal net operating losses (NOLs) and the creation of an NOL-based deferred tax asset. The 2012 GRC decision denied recovery of any return associated with the NOL-based deferred tax asset unless an IRS Private Letter Ruling (PLR) was obtained, at which point SoCalGas would be authorized to file an advice letter seeking an increase to its revenue requirement. In February 2015, the IRS issued a PLR that agreed with SoCalGas’ position that the denial of any return on the NOL-based deferred tax asset was a violation of tax normalization rules.

In March 2015, SoCalGas filed an advice letter to provide the PLR to the CPUC and request an increase to its authorized GRC revenue requirement for 2012 through 2015 to comply with the normalization requirements as interpreted by the IRS in the PLR. In April 2015, the CPUC approved SoCalGas’ advice letter. The approved increases to the pretax annual revenue requirements are $6.4 million for 2012, $6.3 million for 2013, $6.4 million for 2014 and $6.6 million for 2015. The resulting increase to after-tax earnings of an aggregate of $11.3 million for years 2012 through 2014 and $1.4 million and $0.8 million related to the first and second quarters of 2015, respectively, was recorded in the second quarter of 2015. The amount recorded in the third quarter of 2015 was $0.6 million after tax, and the remaining 2015 after-tax earnings of $1.1 million resulting from this revenue increase will be recognized in the fourth quarter of 2015.

NOTE 11. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

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

At September 30, 2015, Sempra Energy’s accrued liabilities for material legal proceedings, including associated legal fees and costs of litigation, on a consolidated basis, were $52 million. At September 30, 2015, accrued liabilities for material legal proceedings for SDG&E and SoCalGas were $27 million and $13 million, respectively.

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. In April 2010, proceedings initiated by the CPUC to determine if any of its rules were violated were settled with SDG&E’s payment of $14.75 million.

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’s settled claims and defense costs have exceeded its $1.1 billion of liability insurance coverage for the covered period and the $824 million recovered from third party contractors and Cox. SDG&E has settled all of the approximately 19,000 claims brought by homeowner insurers for damage to insured property relating to the three fires. Under the settlement agreements, SDG&E agreed to pay 57.5 percent of the approximately $1.6 billion paid or reserved for payment by the insurers to their policyholders and received an assignment of the insurers’ claims against other parties potentially responsible for the fires. Through September 30, 2015, SDG&E has expended $496 million in excess of amounts covered by insurance and amounts recovered from third parties to pay for the settlement of wildfire claims and related costs.

The wildfire litigation also includes claims of approximately 6,500 non-insurer plaintiffs for damage to uninsured and underinsured structures, business interruption, evacuation expenses, agricultural damage, emotional harm, personal injuries and other losses. SDG&E has now resolved all but one of these claims for a total of approximately $1.3 billion. SDG&E does not expect additional plaintiffs to file lawsuits given the applicable statutes of limitation, but could receive additional settlement demands and damage estimates from the remaining plaintiff until the case is resolved. SDG&E establishes reserves for the wildfire litigation as information becomes available and amounts are estimable.

SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of the costs incurred to resolve wildfire claims in excess of its liability insurance coverage and the amounts recovered from third parties. Accordingly, at September 30, 2015, Sempra Energy and SDG&E have recorded assets of $362 million in Other Regulatory Assets (long-term) on their Condensed Consolidated Balance Sheets, including $359 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.

Recovery of the regulatory assets related to the wildfire reserves will require future regulatory approval. SDG&E will continue to assess the likelihood, amount and timing of such recovery in rates. Should SDG&E conclude that recovery in rates is no longer probable, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated at September 30, 2015, 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, 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.

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 is now participating in the arbitration as a claimant and respondent.

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 is disputing 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 January 2016.

Concluded Matter

In February 2011, opponents of the Sunrise Powerlink, a 500-kV electric transmission line between the Imperial Valley and the San Diego region that was energized and placed in service in June 2012, filed a lawsuit in Sacramento County Superior Court against the State Water Resources Control Board and SDG&E alleging that the water quality certification issued by the Board under the Federal Clean Water Act violated the California Environmental Quality Act. The Superior Court denied the plaintiffs’ petition in July 2012, and the plaintiffs appealed. On May 19, 2015 the California Court of Appeals affirmed the lower court’s decision and, on June 16, 2015, denied plaintiffs’ request for rehearing. Plaintiffs did not seek review by the California Supreme Court within the prescribed time, so the Court of Appeals decision is final.

SoCalGas

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 five 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 have challenged the rulings. 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 13 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. Six of the lawsuits have been settled. The remaining seven lawsuits, which include more than 1,000 individual plaintiffs, allege nuisance, fraud and negligence causes of action, and seek unspecified compensatory and punitive damages. An initial trial involving approximately ten plaintiffs is scheduled for January 2016.

Liberty Gas Storage, LLC (Liberty) received a demand for arbitration from Williams Midstream Natural Gas Liquids, Inc. (Williams) in February 2011 related to a sublease agreement. Williams alleged that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage. In August 2015, the parties reached a settlement in principal to resolve this matter for an immaterial amount.

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. 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 $71 million at September 30, 2015 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 nine months of 2015 to contractual commitments discussed in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Natural Gas Contracts

SoCalGas’ natural gas purchase and pipeline capacity commitments have decreased by $120 million since December 31, 2014, primarily due to fulfillment of payment obligations and changes in forward natural gas prices in the first nine months of 2015. Net future payments are expected to decrease by $114 million in 2015, $1 million each year in 2016 through 2019 and $2 million thereafter compared to December 31, 2014.

Sempra Natural Gas’ natural gas purchase and transportation commitments have decreased by $345 million since December 31, 2014, primarily due to payments on existing contracts and changes in forward natural gas prices in the first nine months of 2015. Net future payments are expected to decrease by $219 million in 2015, $41 million in 2016, $45 million in 2017, and $33 million in 2018, increase by $1 million in 2019 and decrease by $8 million thereafter compared to December 31, 2014.

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, 2014 and actual transactions for the first nine months of 2015, are expected to decrease by $322 million in 2015, $128 million in 2016, $163 million in 2017, $194 million in 2018, $195 million in 2019 and $1.4 billion thereafter (through contract termination in 2029) compared to December 31, 2014. These amounts are based on forward prices of the index applicable to the contract from 2015 to 2024 and an estimated one percent escalation per year beyond 2024. The LNG commitment amounts above are based on the requirement for Sempra Natural Gas to accept the maximum possible delivery of cargoes under the agreement. Actual LNG purchases in the current and prior years have been significantly lower than the maximum amounts possible due to the customer electing to divert cargoes as allowed by the agreement.

Purchased-Power Contracts

SDG&E’s commitments under purchased-power contracts have decreased by $362 million since December 31, 2014. Net future payments are expected to increase by $22 million in 2015, $26 million in 2016, and decrease by $14 million in 2017, $16 million in 2018, $21 million in 2019 and $359 million thereafter compared to December 31, 2014.

Operating Leases

Sempra Renewables’ commitments under operating leases have increased by $44 million since December 31, 2014. The increase is primarily due to land leases associated with renewable energy development projects. Net future payments are expected to decrease by $1 million in 2015, and increase by $1 million each year in 2016 through 2017, $2 million each year in 2018 through 2019 and $39 million thereafter compared to December 31, 2014.

Capital Leases – Power Purchase Agreements

In the first quarter of 2015, SDG&E entered into a CPUC-approved 25-year power purchase agreement with a peaker plant facility that is under construction. Beginning with the initial delivery of the contracted power, scheduled in June 2017, the power purchase agreement will be accounted for as a capital lease. Future minimum lease payments under the new power purchase agreement are as follows:

FUTURE MINIMUM PAYMENTS – POWER PURCHASE AGREEMENT
(Dollars in millions)
2015		$	―
2016			―
2017			38
2018			65
2019			65
Thereafter			1,460
Total minimum lease payments(1)			1,628
Less: estimated executory costs			(392)
Less: interest(2)			(736)
Present value of net minimum lease payments		$	500
(1)	This amount will be recorded over the life of the lease as Cost of Electric Fuel and Purchased Power on Sempra Energy’s and SDG&E’s Condensed Consolidated Statements of Operations. This expense will receive ratemaking treatment consistent with purchased-power costs, which are recovered in rates.
(2)	Amount necessary to reduce net minimum lease payments to estimated present value at the inception of the lease.

Construction and Development Projects

In the first nine months of 2015, significant net decreases to contractual commitments at SDG&E were $66 million primarily due to fulfillment of payment obligations, partially offset by an increase in commitments. Net future payments under these contractual commitments are expected to decrease by $144 million in 2015, and increase by $25 million in 2016, $19 million in 2017, $12 million in 2018, $17 million in 2019 and $5 million thereafter compared to December 31, 2014.

In the first nine months of 2015, significant net decreases to contractual commitments at SoCalGas were $137 million primarily due to payments on existing contracts, partially offset by an increase in commitments in the first nine months of 2015. Net future payments under these contractual commitments are expected to decrease by $164 million in 2015, and increase by $20 million in 2016 and $7 million in 2017 compared to December 31, 2014.

In the first nine months of 2015, significant increases to contractual commitments at Sempra Mexico were $41 million, primarily related to pipeline projects. Net future payments under these contractual commitments are expected to decrease by $19 million in 2015, and increase by $59 million in 2016 and $1 million thereafter compared to December 31, 2014.

In the first nine months of 2015, significant increases to contractual commitments at Sempra Renewables were $554 million for contracts related to the construction of renewable energy projects. The future payments under these contractual commitments are expected to be $90 million in 2015 and $464 million in 2016.

In the first nine months of 2015, significant increases to contractual commitments at Sempra Natural Gas were $46 million, primarily for natural gas transportation projects. The future payments under these contractual commitments are all expected to be made in 2015.

OTHER COMMITMENTS

Sempra Natural Gas’ other commitments have decreased by $33 million since December 31, 2014. The decrease is primarily due to a long-term operations and maintenance agreement that was assumed by the purchaser of the remaining 625-MW block of the Mesquite Power plant. We provide additional information about the agreement in Notes 3 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

GUARANTEES

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

NUCLEAR INSURANCE

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

The Nuclear Waste Policy Act of 1982 made the DOE responsible for the disposal 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 seek recovery for these costs from the appropriate sources, including, but not limited to, SDG&E’s Nuclear Decommissioning Trust. SDG&E will also continue to support Edison in its pursuit of legal claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel.

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 is proposed to be installed beginning in 2016, fully loaded with spent fuel by 2020, and operated until 2049, when it is assumed that the Federal Department of Energy will have taken custody of all the SONGS spent fuel. The facility would then be decommissioned, and the site restored.

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

NOTE 12. SEGMENT INFORMATION

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

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

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

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

Sempra Mexico develops, owns and operates, or holds interests in, natural gas transmission pipelines and propane and ethane systems, a 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.

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.

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, as we discuss in Note 3.

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

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

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

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

SEGMENT INFORMATION
(Dollars in millions)
	Three months ended September 30,								Nine months ended September 30,
	2015				2014				2015				2014
REVENUES
SDG&E	$	1,230	50	%	$	1,233	44	%	$	3,168	42	%	$	3,283	40	%
SoCalGas		620	25			855	30			2,448	33			2,857	35
Sempra South American Utilities		373	15			379	14			1,151	15			1,147	14
Sempra Mexico		193	8			234	8			508	7			621	7
Sempra Renewables		12	―			10	―			30	―			25	―
Sempra Natural Gas		160	6			252	9			512	7			748	9
Adjustments and eliminations		―	―			1	―			(1)	―			(1)	―
Intersegment revenues(1)		(107)	(4)			(149)	(5)			(286)	(4)			(392)	(5)
Total	$	2,481	100	%	$	2,815	100	%	$	7,530	100	%	$	8,288	100	%
INTEREST EXPENSE
SDG&E	$	51			$	51			$	155			$	152
SoCalGas		23				17				61				50
Sempra South American Utilities		9				7				22				24
Sempra Mexico		7				5				18				13
Sempra Renewables		1				2				3				3
Sempra Natural Gas		13				25				57				90
All other		65				63				193				178
Intercompany eliminations		(26)				(26)				(93)				(92)
Total	$	143			$	144			$	416			$	418
INTEREST INCOME
SoCalGas	$	―			$	―			$	3			$	―
Sempra South American Utilities		5				4				14				10
Sempra Mexico		1				1				5				2
Sempra Renewables		2				―				3				―
Sempra Natural Gas		16				24				60				87
All other		―				(1)				―				―
Intercompany eliminations		(18)				(22)				(62)				(84)
Total	$	6			$	6			$	23			$	15
DEPRECIATION AND AMORTIZATION
SDG&E	$	152	48	%	$	134	46	%	$	446	48	%	$	395	46	%
SoCalGas		116	37			109	37			342	37			321	37
Sempra South American Utilities		12	4			14	5			37	4			41	5
Sempra Mexico		18	6			16	6			52	6			47	5
Sempra Renewables		2	―			1	―			5	―			4	―
Sempra Natural Gas		12	4			17	6			36	4			50	6
All other		3	1			1	―			7	1			8	1
Total	$	315	100	%	$	292	100	%	$	925	100	%	$	866	100	%
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	75			$	65			$	217			$	217
SoCalGas		(20)				44				91				110
Sempra South American Utilities		16				26				50				59
Sempra Mexico		(6)				13				7				37
Sempra Renewables		(9)				(16)				(37)				(35)
Sempra Natural Gas		―				(31)				29				(22)
All other		(41)				(30)				(81)				(75)
Total	$	15			$	71			$	276			$	291

SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
		Three months ended September 30,								Nine months ended September 30,
		2015				2014				2015				2014
EQUITY EARNINGS (LOSSES)
Earnings recorded before tax:
Sempra Renewables		$	8			$	7			$	20			$	18
Sempra Natural Gas			25				15				59				44
Total		$	33			$	22			$	79			$	62
Earnings (losses) recorded net of tax:
Sempra South American Utilities		$	(3)			$	(2)			$	(4)			$	(4)
Sempra Mexico			30				9				68				26
Total		$	27			$	7			$	64			$	22
EARNINGS (LOSSES)
SDG&E		$	170	69	%	$	157	45	%	$	443	45	%	$	379	44	%
SoCalGas(2)			(8)	(3)			98	28			276	28			256	30
Sempra South American Utilities			43	17			32	9			129	13			109	13
Sempra Mexico			63	25			63	18			160	16			139	16
Sempra Renewables			15	6			17	5			47	5			63	7
Sempra Natural Gas			1	―			26	8			43	5			39	4
All other			(36)	(14)			(45)	(13)			(118)	(12)			(121)	(14)
Total		$	248	100	%	$	348	100	%	$	980	100	%	$	864	100	%
										Nine months ended September 30,
										2015				2014
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E										$	835	38	%	$	790	34	%
SoCalGas											946	42			764	33
Sempra South American Utilities											105	5			126	5
Sempra Mexico											185	8			262	11
Sempra Renewables											47	2			174	8
Sempra Natural Gas											61	3			192	8
All other											48	2			12	1
Total										$	2,227	100	%	$	2,320	100	%
										September 30, 2015				December 31, 2014
ASSETS
SDG&E										$	16,692	41	%	$	16,296	41	%
SoCalGas											11,355	28			10,461	26
Sempra South American Utilities											3,265	8			3,379	9
Sempra Mexico											3,713	9			3,488	9
Sempra Renewables											1,351	3			1,338	3
Sempra Natural Gas											5,552	14			6,436	16
All other											1,118	3			895	2
Intersegment receivables											(2,480)	(6)			(2,561)	(6)
Total										$	40,566	100	%	$	39,732	100	%
INVESTMENTS IN EQUITY METHOD INVESTEES
Sempra South American Utilities										$	(11)			$	(8)
Sempra Mexico											491				434
Sempra Renewables											843				911
Sempra Natural Gas											1,435				1,347
All other											87				164
Total										$	2,845			$	2,848
(1)	Revenues for reportable segments include intersegment revenues of $2 million, $19 million, $24 million and $62 million for the three months ended September 30, 2015; $7 million, $55 million, $73 million and $151 million for the nine months ended September 30, 2015; $2 million, $17 million, $23 million and $107 million for the three months ended September 30, 2014; and $7 million, $51 million, $68 million and $266 million for the nine months ended September 30, 2014 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.
(2)	After preferred dividends.

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

You should read the following discussion in conjunction with the Condensed Consolidated Financial Statements and the Notes thereto contained in this Form 10-Q, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and the Notes thereto contained in our 2014 Annual Report on Form 10-K (Annual Report) and “Risk Factors” contained in our 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 operations are divided principally between our California Utilities, which are San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), and 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 the 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 3.5 million (1.4 million meters) § Provides natural gas to a population of 3.2 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 21.4 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 approximately 2.4 million consumers (approximately 657,000 meters) in Chile and approximately 4.8 million consumers (approximately 1,029,000 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 § natural gas distribution utilities § a terminal in the U.S. for the import and export of LNG and sale of natural gas § marketing operations	§ Natural gas § Liquefied natural gas § Wholesale electricity	§ 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 $100 million (29%) to $248 million in the three months ended September 30, 2015, while diluted earnings per share decreased by $0.40 per share (29%) to $0.99 per share. For the nine months ended September 30, 2015, our earnings increased by $116 million (13%) to $980 million, while diluted earnings per share increased by $0.46 per share (13%) to $3.91 per share.

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

SDG&E

§	$14 million higher earnings from CPUC base operations and from electric transmission

SoCalGas

$(113) million lower earnings due to SoCalGas recognizing annual core gas authorized revenue during interim periods based on seasonal factors starting in 2015 due to the adoption of a Triennial Cost Allocation Proceeding (TCAP) decision by the California Public Utilities Commission (CPUC). Prior to 2015, SoCalGas recognized such revenue ratably over the year. While this “seasonalization” impacts quarterly and quarterly year-to-date comparisons of operating revenues and earnings for both Sempra Energy and SoCalGas, it will not impact full-year results. We discuss the TCAP decision further in Note 10 of the Notes to Condensed Consolidated Financial Statements herein

Sempra South American Utilities

§	$11 million higher earnings from operations, mainly in Peru, due to an increase in volumes and rates, which include foreign currency adjustments

Sempra Mexico

§	$(14) million gain in 2014 from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez wind-powered electric generation project

§	$(8) million lower earnings from operations at our Mexicali power plant primarily due to lower capacity revenues

§	$23 million higher pipeline earnings, primarily due to the start of operations of certain pipelines in the fourth quarter of 2014 and allowance for funds used during construction (AFUDC) related to equity associated with construction of the Los Ramones Norte natural gas pipeline

Sempra Natural Gas

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

Parent and Other

§	$(6) million higher investment losses on dedicated assets in support of our executive retirement and deferred compensation plans, net of the decrease in deferred compensation liability associated with the investments

§	$14 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries, as discussed under “Changes in Revenues, Costs and Earnings – Income Taxes” below

The net increases in our earnings and diluted earnings per share for the nine-month period ended September 30, 2015 were primarily due to the following increases (decreases), by segment:

SDG&E

§	$42 million higher earnings from CPUC base operations and from electric transmission

$13 million reduction to the loss from plant closure in 2015 based on CPUC approval of a compliance filing related to SDG&E’s authorized recovery of its investment in San Onofre Nuclear Generating Station (SONGS) compared to a $9 million increase to the loss in 2014 as a result of reaching a preliminary settlement agreement on the closure, as we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements herein

SoCalGas

§	$23 million due primarily to a lower effective tax rate, including $14 million favorable resolution of prior years’ income tax items in 2015

§	$15 million higher earnings from CPUC base operating margin authorized for 2015

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

§	$11 million increase in AFUDC related to equity

§	$(48) million lower earnings due to SoCalGas recognizing annual core gas authorized revenue during interim periods based on seasonal factors starting in 2015 due to the adoption of a TCAP decision

Sempra South American Utilities

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

Sempra Mexico

§	$54 million higher pipeline earnings, primarily due to the start of operations of certain pipelines in the fourth quarter of 2014 and AFUDC related to equity associated with construction of the Los Ramones Norte natural gas pipeline

§	$(16) million lower earnings from operations at our Mexicali power plant primarily due to lower capacity revenues and lower volumes

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

Sempra Renewables

§	$(16) million gain in 2014 from the sale of a 50-percent equity interest in Copper Mountain Solar 3

Sempra Natural Gas

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

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

Parent and Other

§	$14 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries

§	$(5) million investment losses in 2015 compared to $(9) million investment gains in 2014 on dedicated assets in support of our executive retirement and deferred compensation plans, net of the decrease in deferred compensation liability associated with the investments

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 September 30,								Nine months ended September 30,
		2015				2014				2015				2014
California Utilities:
SDG&E		$	170	69	%	$	157	45	%	$	443	45	%	$	379	44	%
SoCalGas(1)			(8)	(3)			98	28			276	28			256	30
Sempra International:
Sempra South American Utilities			43	17			32	9			129	13			109	13
Sempra Mexico			63	25			63	18			160	16			139	16
Sempra U.S. Gas & Power:
Sempra Renewables			15	6			17	5			47	5			63	7
Sempra Natural Gas			1	―			26	8			43	5			39	4
Parent and other(2)			(36)	(14)			(45)	(13)			(118)	(12)			(121)	(14)
Earnings		$	248	100	%	$	348	100	%	$	980	100	%	$	864	100	%
(1)	After preferred dividends.
(2)	Includes after-tax interest expense ($38 million and $37 million for the three months ended September 30, 2015 and 2014, respectively, and $115 million and $106 million for the nine months ended September 30, 2015 and 2014, 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 presented in the table above. Variance amounts are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise noted.

EARNINGS (LOSSES) BY SEGMENT – CALIFORNIA UTILITIES

(Dollars in millions)

[graph1.gif]

SDG&E

Our SDG&E segment recorded earnings of:

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

§	$157 million in the three months ended September 30, 2014

§	$443 million for the first nine months of 2015

§	$379 million for the first nine months of 2014

The increase in earnings of $13 million (8%) in the three months ended September 30, 2015 was primarily due to:

§	$8 million higher CPUC base operating margin authorized for 2015, and lower non-refundable operating costs; and

§	$6 million higher earnings from electric transmission operations primarily due to higher rate base.

The increase in earnings of $64 million (17%) in the first nine months of 2015 was primarily due to:

§	$23 million higher CPUC base operating margin authorized for 2015, and lower non-refundable operating costs;

$13 million reduction to the loss from plant closure in 2015 based on the CPUC approval of a compliance filing related to SDG&E’s authorized recovery of its investment in SONGS compared to a $9 million increase to the loss in 2014 as a result of reaching a preliminary settlement agreement on the closure;

§	$19 million higher earnings from electric transmission operations primarily due to higher rate base; and

§	$9 million higher favorable resolution of prior years’ income tax items; offset by

§	$7 million higher earnings in 2014 associated with SDG&E’s annual Federal Energy Regulatory Commission (FERC) formulaic rate adjustment; and

§	$3 million favorable settlement in 2014 associated with a long-term service agreement.

SoCalGas

Our SoCalGas segment recorded (losses) earnings of:

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

§	$98 million in the three months ended September 30, 2014 (both before and after preferred dividends)

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

§	$256 million for the first nine months of 2014 ($257 million before preferred dividends)

The reduction in earnings of $106 million in the three months ended September 30, 2015 was primarily due to:

§	$113 million lower earnings resulting from the seasonalization of interim period recognition of annual core gas authorized revenue starting in 2015 (after-tax impact is based on SoCalGas’ effective tax rate); offset by

§	$11 million favorable resolution of prior years’ income tax items in 2015.

The increase in earnings of $20 million (8%) in the first nine months of 2015 was primarily due to:

§	$23 million due primarily to a lower effective tax rate, as we discuss under “Income Taxes” below, including $14 million favorable resolution of prior years’ income tax items in 2015;

§	$15 million higher CPUC base operating margin authorized for 2015 and lower non-refundable operating costs;

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

§	$11 million increase in AFUDC related to equity;

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

§	$5 million higher gas cost incentive mechanism (GCIM) awards; and

§	$5 million write-off in 2014 of certain costs incurred that were disallowed for recovery in the final PSEP decision; offset by

§	$48 million lower earnings resulting from the seasonalization of interim period recognition of annual core gas authorized revenue starting in 2015 (after-tax impact is based on SoCalGas’ effective tax rate); and

§	$7 million higher interest expense.

EARNINGS BY SEGMENT – SEMPRA INTERNATIONAL

(Dollars in millions)

[graph2.gif]

Sempra South American Utilities

Our Sempra South American Utilities segment recorded earnings of:

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

§	$32 million in the three months ended September 30, 2014

§	$129 million for the first nine months of 2015

§	$109 million for the first nine months of 2014

The increase in earnings of $11 million (34%) in the three months ended September 30, 2015 was primarily due to:

§	$11 million higher earnings from operations, mainly in Peru, due to an increase in volumes and rates, which include foreign currency adjustments; and

$9 million lower income tax expense, including $6 million recorded in 2014 related to Chilean tax reform, as we discuss 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; offset by

§	$6 million lower earnings from foreign currency effects.

The increase in earnings of $20 million (18%) in the first nine months of 2015 was primarily due to:

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

§	$11 million lower income tax expense, including $6 million recorded in 2014 related to Chilean tax reform; and

§	$4 million lower interest expense, mainly in Chile, related to inflationary effect on local bonds; offset by

§	$15 million lower earnings from foreign currency effects.

Sempra Mexico

Our Sempra Mexico segment recorded earnings of:

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

§	$63 million in the three months ended September 30, 2014

§	$160 million for the first nine months of 2015

§	$139 million for the first nine months of 2014

Earnings in the three months ended September 30, 2015 compared to the three months ended September 30, 2014 included

$23 million higher pipeline earnings, primarily due to the start of operations of certain pipelines in the fourth quarter of 2014 and AFUDC related to equity associated with construction of the Los Ramones Norte natural gas pipeline, which is being developed through a joint venture with Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company) and affiliates of PEMEX; and

§	$12 million favorable income tax variance primarily due to the effects from foreign currency and inflation; offset by

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

§	$8 million lower earnings from operations at our Mexicali power plant primarily due to lower capacity revenues;

§	$7 million lower AFUDC related to equity associated with construction of the natural gas pipeline in Sonora; and

§	$5 million unfavorable translation effect primarily on Peso-denominated receivables.

The increase in earnings of $21 million (15%) in the first nine months of 2015 was primarily due to:

§	$54 million higher pipeline earnings, primarily due to the start of operations of certain pipelines in the fourth quarter of 2014 and AFUDC related to equity associated with construction of the Los Ramones Norte natural gas pipeline;

§	$21 million favorable income tax variance primarily due to the effects from foreign currency and inflation; and

§	$7 million higher earnings from the Energía Sierra Juárez joint venture due to the start of operations during the second quarter of 2015; offset by

§	$16 million lower earnings from operations at our Mexicali power plant primarily due to lower capacity revenues and lower volumes;

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

§	$10 million unfavorable translation effect primarily on Peso-denominated receivables;

§	$7 million increase in earnings attributable to noncontrolling interests at IEnova;

§	$6 million lower AFUDC related to equity associated with construction of the natural gas pipeline in Sonora; and

§	$5 million lower earnings mainly from LNG operations.

EARNINGS BY SEGMENT – SEMPRA U.S. GAS & POWER

(Dollars in millions)

[graph3.gif]

Sempra Renewables

Our Sempra Renewables segment recorded earnings of:

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

§	$17 million in the three months ended September 30, 2014

§	$47 million for the first nine months of 2015

§	$63 million for the first nine months of 2014

Earnings for the three months ended September 30, 2015 were consistent with earnings for the same period in 2014.

The decrease in earnings of $16 million (25%) in the first nine months of 2015 was primarily due to a $16 million gain in 2014 from the sale of a 50-percent equity interest in Copper Mountain Solar 3.

Sempra Natural Gas

Our Sempra Natural Gas segment recorded earnings of:

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

§	$26 million in the three months ended September 30, 2014

§	$43 million for the first nine months of 2015

§	$39 million for the first nine months of 2014

The decrease in earnings of $25 million in the three months ended September 30, 2015 was primarily due to:

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

§	$6 million lower results from LNG marketing operations, including the effect of lower gas prices; offset by

§	$7 million higher earnings from mark-to-market gains on commodity contracts.

The increase in earnings of $4 million (10%) in the first nine months of 2015 was primarily due to:

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

§	$16 million improved results from midstream activities; and

§	$8 million higher earnings from mark-to-market gains on commodity contracts and lower costs from the Mesquite Power plant due to the sale of the remaining block in April 2015; offset by

§	$26 million lower results from LNG marketing operations, including the effect of lower gas prices;

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

§	$7 million in development expense associated with the potential expansion of our LNG business.

Parent and Other

Losses for Parent and Other were

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

§	$45 million in the three months ended September 30, 2014

§	$118 million for the first nine months of 2015

§	$121 million for the first nine months of 2014

The decrease in losses of $9 million (20%) in the three months ended September 30, 2015 was primarily due to:

§	$14 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries; offset by

§	$6 million higher investment losses on dedicated assets in support of our executive retirement and deferred compensation plans, net of the decrease in deferred compensation liability associated with the investments.

The decrease in losses of $3 million (2%) in the first nine months of 2015 was primarily due to:

§	$16 million higher income tax benefits, including

□	$14 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries,

□	$5 million higher income tax benefits from a decrease in state valuation allowances, and

□	$5 million in net state income tax refunds related to our former commodities-marketing businesses, offset by

□	$6 million of income tax expense associated with the resolution of prior years’ income tax items in 2015; offset by

§	$5 million investment losses in 2015 compared to $9 million investment gains in 2014 on dedicated assets in support of our executive retirement and deferred compensation plans, net of the decrease in deferred compensation liability associated with the investments.

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’ gas cost incentive mechanism provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in Notes 1 and 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.

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 the next year through rates.

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

UTILITIES REVENUES AND COST OF SALES
(Dollars in millions)
		Three months ended September 30,				Nine months ended September 30,
		2015		2014		2015		2014
Electric revenues:
SDG&E		$	1,140	$	1,133	$	2,819	$	2,892
Sempra South American Utilities			351		354		1,077		1,072
Eliminations and adjustments			(2)		(2)		(6)		(7)
	Total		1,489		1,485		3,890		3,957
Natural gas revenues:
SoCalGas			620		855		2,448		2,857
SDG&E			90		100		349		391
Sempra Mexico			18		23		62		82
Sempra Natural Gas			16		17		76		84
Eliminations and adjustments			(20)		(17)		(57)		(53)
	Total		724		978		2,878		3,361
Total utilities revenues		$	2,213	$	2,463	$	6,768	$	7,318
Cost of electric fuel and purchased power:
SDG&E		$	427	$	441	$	906	$	1,036
Sempra South American Utilities			239		239		739		725
	Total	$	666	$	680	$	1,645	$	1,761
Cost of natural gas:
SoCalGas		$	163	$	237	$	626	$	1,066
SDG&E			27		39		112		165
Sempra Mexico			12		16		38		56
Sempra Natural Gas			4		6		24		33
Eliminations and adjustments			(5)		(5)		(14)		(12)
	Total	$	201	$	293	$	786	$	1,308

Sempra Energy Consolidated

Electric Revenues

During the three months ended September 30, 2015, our electric revenues increased by $4 million, remaining at $1.5 billion primarily due to:

§	$7 million increase at SDG&E, which included

□

$23 million higher revenues from CPUC-authorized 2015 attrition and, starting in 2015, authorized revenues for the recovery of the SONGS regulatory assets pursuant to an amended settlement agreement approved by the CPUC in 2014. The GRC decision for years 2012 through 2015 established a revenue attrition mechanism for the escalation of adopted revenue requirements based on fixed annual factors, and

□	$18 million higher authorized revenues from electric transmission, offset by

□	$19 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses, and

□	$14 million lower cost of electric fuel and purchased power, which we discuss below; offset by

§	$3 million decrease at Sempra South American Utilities, primarily due to foreign currency exchange rate effects, offset by higher rates at both Luz del Sur and Chilquinta Energía.

Our utilities’ cost of electric fuel and purchased power decreased by $14 million (2%) to $666 million in the three months ended September 30, 2015 due to SDG&E, which we discuss below.

During the nine months ended September 30, 2015, our electric revenues decreased by $67 million (2%) to $3.9 billion primarily due to:

§	$73 million decrease at SDG&E, which included

□	$130 million lower cost of electric fuel and purchased power, which we discuss below, and

□	$34 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses, offset by

□	$66 million higher revenues from CPUC-authorized 2015 attrition and, starting in 2015, authorized revenues for the recovery of the SONGS regulatory assets pursuant to an amended settlement agreement approved by the CPUC in 2014, and

□	$35 million higher authorized revenues from electric transmission; offset by

$5 million increase at Sempra South American Utilities, primarily due to higher rates at both Luz del Sur and Chilquinta Energía and higher volumes at Luz del Sur, offset by foreign currency exchange rate effects. Volumes decreased at Chilquinta Energía due to a transfer of customers to our energy-services companies in Chile.

Our utilities’ cost of electric fuel and purchased power decreased by $116 million (7%) to $1.6 billion in the nine months ended September 30, 2015 due to:

§	$130 million decrease at SDG&E, which we discuss below; offset by

$14 million increase at Sempra South American Utilities driven primarily by higher rates at both Luz del Sur and Chilquinta Energía and higher volumes at Luz del Sur, offset by foreign currency exchange rate effects. Volumes decreased at Chilquinta Energía due to a transfer of customers to our energy-services companies in Chile.

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

Natural Gas Revenues

During the three months ended September 30, 2015, Sempra Energy’s natural gas revenues decreased by $254 million (26%) to $724 million, and the cost of natural gas decreased by $92 million (31%) to $201 million. The decrease in natural gas revenues included

§	$158 million decrease resulting from the seasonalization of interim period recognition of annual core gas authorized revenue at SoCalGas starting in 2015;

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

§	$13 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

§	$13 million higher revenues from CPUC-authorized 2015 attrition at SoCalGas.

During the first nine months of 2015, Sempra Energy’s natural gas revenues decreased by $483 million (14%) to $2.9 billion, and the cost of natural gas decreased by $522 million (40%) to $786 million. The decrease in natural gas revenues included

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

§	$67 million decrease resulting from the seasonalization of interim period recognition of annual core gas authorized revenue at SoCalGas starting in 2015; offset by

§	$50 million higher revenues from CPUC-authorized 2015 attrition at the California Utilities;

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

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

§	$8 million higher GCIM awards at SoCalGas.

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

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

The table below shows electric revenues for SDG&E for the nine months ended September 30, 2015 and 2014. 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)
		Nine months ended September 30, 2015			Nine months ended September 30, 2014
Customer class		Volumes	Revenue		Volumes	Revenue
Residential		5,257	$	1,096	5,501	$	1,042
Commercial		5,112		1,116	5,245		1,048
Industrial		1,519		268	1,556		251
Direct access(1)		2,683		170	2,761		150
Street and highway lighting		62		11	66		11
		14,633		2,661	15,129		2,502
CAISO shared transmission revenue - net(2)				214			137
Other revenues				166			144
Balancing accounts				(222)			109
Total(3)			$	2,819		$	2,892
(1)	The Direct Access (DA) program, which offered all customers the option to purchase their electric commodity services from a third-party Energy Service Provider instead of continuing to receive these services from SDG&E, was implemented in 1998 and suspended in 2001. In 2009, Senate Bill 695 required the CPUC to develop a process and rules for a limited re-opening of DA to be phased in over a period of time. In 2010, the CPUC adopted the process and rules for the limited re-opening of DA for non-residential customers under a 4-year phase-in schedule.
(2)	California Independent System Operator (CAISO).
(3)	Includes sales to affiliates of $6 million in each of 2015 and 2014.

For the three months ended September 30, 2015, SDG&E’s electric revenues increased by $7 million (1%) remaining at $1.1 billion. The change was primarily due to:

§	$23 million higher revenues from CPUC-authorized 2015 attrition and, starting in 2015, authorized revenues for the recovery of the SONGS regulatory assets pursuant to an amended settlement agreement approved by the CPUC in 2014; and

§	$18 million higher authorized revenues from electric transmission; offset by

§	$19 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; and

§	$14 million decrease in cost of electric fuel and purchased power, including:

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

□	lower demand due to regional climatic impacts and a decrease in consumption due to energy efficiency initiatives, including an increase in rooftop solar installations, in the third quarter of 2015 compared to the same period in 2014, offset by

□	an increase from the incremental purchase of renewable energy at higher prices.

In the first nine months of 2015, SDG&E’s electric revenues decreased by $73 million (3%) to $2.8 billion primarily due to:

§	$130 million decrease in cost of electric fuel and purchased power, including:

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

□	lower demand due to regional climatic impacts and a decrease in consumption due to energy efficiency initiatives, including an increase in rooftop solar installations, in 2015 compared to the same period in 2014, offset by

□	an increase from the incremental purchase of renewable energy at higher prices; and

§	$34 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; offset by

§	$66 million higher revenues from CPUC-authorized 2015 attrition and, starting in 2015, authorized revenues for the recovery of the SONGS regulatory assets pursuant to an amended settlement agreement approved by the CPUC in 2014; and

§	$35 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 nine months ended September 30, 2015 and 2014. 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
Nine months ended September 30, 2015:
Residential		18	$	222	―	$	2	18	$	224
Commercial and industrial		10		74	6		10	16		84
Electric generation plants		―		―	20		―	20		―
		28	$	296	26	$	12	54		308
Other revenues										31
Balancing accounts										10
Total(1)									$	349
Nine months ended September 30, 2014:
Residential		21	$	241	―	$	―	21	$	241
Commercial and industrial		11		83	6		8	17		91
Electric generation plants		―		―	19		1	19		1
		32	$	324	25	$	9	57		333
Other revenues										31
Balancing accounts										27
Total(1)									$	391
(1)	Includes sales to affiliates of $2 million in each of 2015 and 2014.

During the three months ended September 30, 2015, SDG&E’s natural gas revenues decreased by $10 million (10%) to $90 million, while the cost of natural gas sold decreased by $12 million (31%) to $27 million. The decrease in revenues was primarily due to lower cost of natural gas sold, as we discuss below.

SDG&E’s average cost of natural gas for the three months ended September 30, 2015 was $4.07 per thousand cubic feet (Mcf) compared to $5.65 per Mcf for the corresponding period in 2014, a 28-percent decrease of $1.58 per Mcf, resulting in lower revenues and cost of $10 million.

During the nine months ended September 30, 2015, SDG&E’s natural gas revenues decreased by $42 million (11%) to $349 million, and the cost of natural gas sold decreased by $53 million (32%) to $112 million. The decrease in revenues was primarily due to:

§	lower cost of natural gas sold, and lower demand, as we discuss below; offset by

§	$6 million increase in revenues from CPUC-authorized 2015 attrition; and

§	$3 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses.

SDG&E’s average cost of natural gas for the nine months ended September 30, 2015 was $3.94 per Mcf compared to $5.52 per Mcf for the corresponding period in 2014, a 29-percent decrease of $1.58 per Mcf, resulting in lower revenues and cost of $45 million. The decrease in the cost of natural gas sold was also due to lower demand for natural gas primarily from a warmer winter in 2015 compared to the same period in 2014, which resulted in lower revenues and cost of $8 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
Nine months ended September 30, 2015:
Residential		132	$	1,373	2	$	12	134	$	1,385
Commercial and industrial		67		451	213		198	280		649
Electric generation plants		―		―	147		31	147		31
Wholesale		―		―	112		20	112		20
		199	$	1,824	474	$	261	673		2,085
Other revenues										131
Balancing accounts										232
Total(1)									$	2,448
Nine months ended September 30, 2014:
Residential		139	$	1,564	2	$	10	141	$	1,574
Commercial and industrial		68		563	220		197	288		760
Electric generation plants		―		―	156		32	156		32
Wholesale		―		―	109		18	109		18
		207	$	2,127	487	$	257	694		2,384
Other revenues										74
Balancing accounts										399
Total(1)									$	2,857
(1)	Includes sales to affiliates of $55 million in 2015 and $51 million in 2014.

During the three months ended September 30, 2015, SoCalGas’ natural gas revenues decreased by $235 million (27%) to $620 million, and the cost of natural gas sold decreased by $74 million (31%) to $163 million. The revenue decrease included

§	$158 million decrease resulting from the seasonalization of interim period recognition of annual core gas authorized revenue starting in 2015;

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

§	$13 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; and

§	$6 million GCIM award approved in 2014; offset by

§	$13 million increase in revenues from CPUC-authorized 2015 attrition.

SoCalGas’ average cost of natural gas for the three months ended September 30, 2015 was $3.40 per Mcf compared to $4.75 per Mcf for the corresponding period in 2014, a 28-percent decrease of $1.35 per Mcf, resulting in lower revenues and cost of $65 million. The decrease in the cost of natural gas sold was also due to lower sales volumes, which resulted in lower revenues and cost of $9 million. The lower sales volumes were mainly driven by a decrease in water heating natural gas consumption due to water conservation efforts.

During the nine months ended September 30, 2015, SoCalGas’ natural gas revenues decreased by $409 million (14%) to $2.4 billion, and the cost of natural gas sold decreased by $440 million (41%) to $626 million. The revenue decrease included

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

§	$67 million decrease resulting from the seasonalization of interim period recognition of annual core gas authorized revenue starting in 2015; offset by

§	$44 million higher revenues from CPUC-authorized 2015 attrition;

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

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

§	$9 million write-off in 2014 of certain costs incurred that were disallowed for recovery in the final PSEP decision; and

§	$8 million higher GCIM awards.

For the first nine months of 2015, SoCalGas’ average cost of natural gas was $3.16 per Mcf compared to $5.15 per Mcf for the corresponding period in 2014, a 39-percent decrease of $1.99 per Mcf, resulting in lower revenues and cost of $392 million. The decrease in the cost of natural gas sold was also due to lower demand for natural gas primarily from a warmer winter in 2015 compared to the same period in 2014, which resulted in lower revenues and cost of $48 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 revenues for our utilities outside of California for the nine-month periods ended September 30, 2015 and 2014:

OTHER UTILITIES
NATURAL GAS AND ELECTRIC REVENUES
(Dollars in millions)
	Nine months ended September 30, 2015			Nine months ended September 30, 2014
	Volumes	Revenue		Volumes	Revenue
Natural Gas Sales (billion cubic feet):
Sempra Mexico – Ecogas	19	$	62	18	$	82
Sempra Natural Gas:
Mobile Gas (including transportation)	35		62	29		66
Willmut Gas	2		14	2		18
Total	56	$	138	49	$	166

Electric Sales (million kilowatt hours):
Sempra South American Utilities:
Luz del Sur	5,695	$	663	5,458	$	642
Chilquinta Energía	2,172		384	2,192		394
	7,867		1,047	7,650		1,036
Other service revenues			30			36
Total		$	1,077		$	1,072

Energy-Related Businesses: Revenues and Cost of Sales

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

ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
		Three months ended September 30,				Nine months ended September 30,
		2015		2014		2015		2014
Energy-related businesses revenues:
Sempra South American Utilities		$	22	$	25	$	74	$	75
Sempra Mexico			175		211		446		539
Sempra Renewables			12		10		30		25
Sempra Natural Gas			144		235		436		664
Intersegment revenues, adjustments
and eliminations(1)			(85)		(129)		(224)		(333)
Total energy-related businesses revenues		$	268	$	352	$	762	$	970
Cost of natural gas, electric fuel
and purchased power(2):
Sempra South American Utilities		$	3	$	3	$	19	$	10
Sempra Mexico			71		108		167		272
Sempra Natural Gas			101		179		293		473
Adjustments and eliminations(1)			(84)		(127)		(217)		(328)
Total cost of natural gas, electric fuel
and purchased power		$	91	$	163	$	262	$	427
Other cost of sales(2):
Sempra South American Utilities		$	17	$	17	$	46	$	50
Sempra Mexico			3		4		12		9
Sempra Natural Gas			15		23		58		69
Adjustments and eliminations(1)			(1)		(2)		(5)		(6)
Total other cost of sales		$	34	$	42	$	111	$	122
(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 September 30, 2015, revenues from our energy-related businesses decreased by $84 million (24%) to $268 million. The decrease included

§	$91 million decrease at Sempra Natural Gas mainly from lower natural gas prices, as well as from the deconsolidation of Cameron LNG, LLC as of October 1, 2014; and

$36 million lower revenues at Sempra Mexico primarily due to lower natural gas prices and volumes in its gas business and lower power prices and capacity revenues in its power business, offset by higher transportation revenues from a section of the Sonora natural gas pipeline that commenced operations in the fourth quarter of 2014; offset by

§	$44 million primarily from lower intercompany eliminations associated with sales between Sempra Natural Gas and Sempra Mexico.

During the three months ended September 30, 2015, the cost of natural gas, electric fuel and purchased power for our energy-related businesses decreased by $72 million (44%) to $91 million primarily due to:

§	$78 million decrease at Sempra Natural Gas primarily due to lower natural gas costs and lower electric fuel costs due to the sale of the remaining block of Mesquite Power in April 2015; and

§	$37 million decrease at Sempra Mexico primarily due to lower natural gas costs and volumes; offset by

§	$43 million from lower intercompany eliminations of costs associated with sales between Sempra Natural Gas and Sempra Mexico.

For the first nine months of 2015, revenues from our energy-related businesses decreased by $208 million (21%) to $762 million. The decrease included

§	$228 million decrease at Sempra Natural Gas mainly from lower natural gas prices, as well as from the deconsolidation of Cameron LNG, LLC as of October 1, 2014; and

$93 million lower revenues at Sempra Mexico primarily due to lower natural gas prices and volumes in its gas business and lower power prices and volumes and lower capacity revenues in its power business, offset by higher transportation revenues from a section of the Sonora natural gas pipeline that commenced operations in the fourth quarter of 2014; offset by

§	$109 million from lower intercompany eliminations associated with sales between Sempra Natural Gas and Sempra Mexico.

For the first nine months of 2015, the cost of natural gas, electric fuel and purchased power for our energy-related businesses decreased by $165 million (39%) to $262 million primarily due to:

§	$180 million decrease at Sempra Natural Gas primarily due to lower natural gas costs and lower electric fuel costs due to the sale of the remaining block of Mesquite Power in April 2015; and

§	$105 million decrease at Sempra Mexico primarily due to lower natural gas costs and volumes; offset by

§	$111 million from lower intercompany eliminations of costs associated with sales between Sempra Natural Gas and Sempra Mexico.

Operation and Maintenance

Sempra Energy Consolidated

Our operation and maintenance expenses decreased by $25 million (3%) to $701 million in the three months ended September 30, 2015 and decreased by $59 million (3%), remaining at $2.1 billion in the first nine months of 2015.

SDG&E

For the three months ended September 30, 2015, SDG&E’s operation and maintenance expenses decreased by $25 million (9%) to $251 million primarily due to:

§	$21 million lower expenses associated with CPUC-authorized refundable programs, for which all costs incurred are fully recovered in revenue (refundable program expenses); and

§	$4 million lower litigation expense.

In the first nine months of 2015, SDG&E’s operation and maintenance expenses decreased by $61 million (8%) to $723 million primarily due to:

§	$31 million lower expenses associated with CPUC-authorized refundable programs, for which all costs incurred are fully recovered in revenue (refundable program expenses);

§	$26 million lower non-refundable operating costs, including $13 million lower major maintenance costs at its electric generating facilities, as well as labor, contract services and administrative and support costs; and

§	$4 million lower litigation expense.

SoCalGas

For the three months ended September 30, 2015, SoCalGas’ operation and maintenance expenses decreased by $1 million to $325 million primarily due to:

§	$13 million lower expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses); offset by

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

In the first nine months of 2015, SoCalGas’ operation and maintenance expenses increased by $17 million (2%) to $985 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); offset by

§	$2 million lower litigation expense, including $6 million from the favorable resolution of a legal settlement in 2015, offset by $4 million higher other litigation expense.

Plant Closure Adjustment

SDG&E has a 20-percent ownership interest in SONGS, a nuclear generating facility near San Clemente, California. SONGS’ Units 2 and 3 were shut down in early 2012 due to steam generator issues, and, in June 2013, Southern California Edison, the majority owner and operator of SONGS, made a decision to permanently retire these two units. In the second quarter of 2013, SDG&E recorded a pretax charge of $200 million, which represents the portion of SDG&E’s investment in SONGS and associated costs that management estimated may not be recovered in rates based on prior CPUC precedent. In addition to the plant closure loss recorded in 2013, during the first quarter of 2014, SDG&E recorded a $13 million pretax reduction to the loss from plant closure. During the first quarter of 2015, SDG&E recorded a $21 million pretax reduction to the loss from plant closure. We discuss SONGS further in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.

Gain on Sale of Equity Interests and Assets

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

Also included in this line item are gains on the sale of 50-percent equity interests in 2014 as follows:

§	$19 million ($14 million after-tax) for the first phase of the Energía Sierra Juárez project (in the third quarter)

§	$27 million ($16 million after-tax) for Copper Mountain Solar 3 (in the first quarter)

Equity Earnings, Before Income Tax

For the first nine months of 2015, our equity earnings, before income tax, increased by $17 million (27%) to $79 million. The increase included:

§	$9 million higher equity earnings from Rockies Express Pipeline, LLC; and

§	$6 million equity earnings in 2015 from Cameron LNG Holdings, which include amortization of the completion guarantee related to the financing agreements described in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Income, Net

Sempra Energy Consolidated

For the three months and nine months ended September 30, 2015, other income, net, decreased by $17 million and $30 million, respectively.

The decrease in the three-month period was primarily due to:

§	$9 million higher investment losses in 2015 on dedicated assets in support of our executive retirement and deferred compensation plans;

§	$4 million of electrical infrastructure income in Peru in 2014; and

§	$2 million net decrease in equity-related AFUDC.

The decrease in the nine-month period was primarily due to:

§	$5 million investment losses in 2015 compared to $20 million gains in 2014 on dedicated assets in support of our executive retirement and deferred compensation plans;

§	$7 million losses on interest rate and foreign exchange instruments in 2015 compared to $3 million gains in 2014; and

§	$5 million higher foreign currency losses in 2015; offset by

§	$7 million net increase in equity-related AFUDC, including $11 million at SoCalGas; and

§	$7 million higher income from the sale of other investments.

Interest Expense

For the first nine months of 2015, our interest expense decreased by $2 million to $416 million. The decrease included:

§	$33 million decrease at Sempra Natural Gas primarily related to capitalized interest for the Cameron liquefaction project; offset by

§	$15 million increase in long-term debt interest at SoCalGas primarily due to debt issuances in 2014 and 2015; and

§	$15 million increase in long-term debt interest at Parent and Other primarily due to debt issuances in 2014 and 2015, net of maturities.

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 (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
		Income tax	Effective				Effective
		expense	income			Income tax	income
		(benefit)	tax rate			expense	tax rate
		Three months ended September 30,
		2015				2014
Sempra Energy Consolidated	$	15	6	%	$	71	16	%
SDG&E		75	29			65	28
SoCalGas		(20)	71			44	31
		Nine months ended September 30,
		2015				2014
Sempra Energy Consolidated	$	276	22	%	$	291	24	%
SDG&E		217	32			217	35
SoCalGas		91	25			110	30

As we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein, 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 on a full year basis are factored into the forecasted effective tax rate, and their impact is recognized proportionately over the year. Items that cannot be reliably forecasted are recorded in the interim period in which they actually occur, which can result in variability to income tax expense.

Sempra Energy Consolidated

The decrease in income tax expense in the three months ended September 30, 2015 was due to lower pretax income and a lower effective tax rate, primarily from:

§	$12 million higher favorable resolution of prior years’ income tax items in 2015;

§	$9 million higher income tax benefit in 2015 from foreign currency translation and inflation adjustments; and

§	$14 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries, as discussed below; offset by

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

The decrease in income tax expense in the nine months ended September 30, 2015 was due to a lower effective tax rate, offset by higher pretax income. The lower effective tax rate was primarily from:

§	$17 million charge in 2014 to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS that we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements herein;

§	$19 million higher favorable resolution of prior years’ income tax items in 2015;

§	$22 million higher income tax benefit in 2015 from foreign currency translation and inflation adjustments; and

§	$14 million lower U.S. income tax expense in 2015 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries, as discussed below; offset by

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

As noted 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, repatriated earnings are subject to U.S. income tax, and repatriation from Peru is subject to local country withholding tax. We no longer plan to repatriate current year 2015 earnings from our non-U.S. subsidiaries in Mexico due to IEnova’s pending acquisition of its joint venture partner’s 50-percent interest in Gasoductos de Chihuahua (GdC), which we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein. We plan to repatriate, in the future, current year earnings from certain of our non-U.S. subsidiaries in Peru, and accordingly, we are accruing tax expense on the current year earnings. Because this potential repatriation from Peru would only be from earnings since January 1, 2015, it does not change our current assertion that we intend to continue to indefinitely reinvest our cumulative undistributed non-U.S. earnings from prior years. Therefore, we do not intend to use these cumulative undistributed earnings as a source of funding for U.S. operations.

Due to the extension of bonus depreciation, Sempra Energy generated a U.S. federal net operating loss (NOL) in 2011, 2012, 2013 and 2014. We further discuss the impact of NOLs on Sempra Energy 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 and in Note 6 of the Notes to Consolidated Financial Statements in the Annual Report.

In 2015, we anticipate that Sempra Energy Consolidated’s effective income tax rate will be approximately 23 percent compared to 20 percent in 2014, before any impact from the anticipated acquisition of PEMEX’s 50-percent interest in GdC in 2015. This increase is primarily due to a forecasted increase in pretax income, higher forecasted depreciation on a certain portion of utility plant assets, and lower renewable energy income tax credits, offset by income tax benefits in 2015 resulting from foreign currency translation and inflation adjustments, lower planned repatriation of current year earnings from certain non-U.S. subsidiaries, and higher favorable resolution of prior years’ income tax issues.

SDG&E

The increase in SDG&E’s income tax expense in the three months ended September 30, 2015 was due to higher pretax income and a higher effective tax rate, primarily from:

§	higher unfavorable impact on our effective tax rate in 2015 from the reversal through book depreciation of previously recognized tax benefits for a certain portion of utility fixed assets; offset by

§	higher exclusions from taxable income of the equity portion of AFUDC.

While SDG&E’s income tax expense remained the same in the nine months ended September 30, 2015, the effect of higher pretax income was offset by a lower effective tax rate, primarily from:

§	$17 million charge in 2014 to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS that we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements herein; and

§	$9 million higher favorable resolution of prior years’ income tax items in 2015.

In 2015, we anticipate that SDG&E’s effective income tax rate will be approximately 34 percent, the same as the prior year. The effect of higher forecasted pretax income is offset by the one-time charge in 2014 to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS.

SoCalGas

SoCalGas’ income tax benefit in the three months ended September 30, 2015 compared to income tax expense in the same period in 2014 was due to a pretax loss in 2015 and a higher effective tax rate. The pretax loss was primarily due to recognizing core gas authorized revenue during interim periods based on seasonal factors beginning January 1, 2015 in accordance with the TCAP, compared to recognizing such revenue ratably over the year in 2014. We discuss the impact of the TCAP decision further in Note 10 of the Notes to Condensed Consolidated Financial Statements herein. The higher effective tax rate applied to the pretax loss was primarily due to:

§	$11 million higher favorable resolution of prior years’ income tax items in 2015; and

§	lower flow-through component of state income taxes.

The decrease in SoCalGas’ income tax expense in the nine months ended September 30, 2015 was mainly due to a lower effective tax rate, primarily from:

§	$14 million higher favorable resolution of prior years’ income tax items in 2015; and

§	higher exclusions from taxable income of the equity portion of AFUDC.

In 2015, we anticipate that SoCalGas’ effective income tax rate will be approximately 26 percent compared to 29 percent in 2014. This decrease is primarily due to a higher favorable impact from self-developed software expenditures, repairs to certain utility plant assets, and the higher favorable resolution of prior years’ income tax issues, offset by higher forecasted pretax income.

SDG&E and SoCalGas both generated a large U.S. federal NOL in 2011 and 2012, primarily due to bonus depreciation. We further discuss the impact of NOLs on 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 and in Note 6 of the Notes to Consolidated Financial Statements in the Annual Report.

Foreign Currency Exchange Rate and Inflation Impact on Income Taxes and Related Economic Hedging Activity

Our Mexican subsidiaries have U.S. dollar denominated cash balances, receivables and payables (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 that are denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes.

The fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar, with regard to Mexican monetary assets and liabilities, and Mexican inflation are subject to Mexican income tax and thus may expose us to fluctuations in our income tax expense. The income tax expense of Sempra Mexico is impacted by these factors. Subsequent to the acquisition of PEMEX’s 50-percent interest in GdC by IEnova, which is discussed in Note 3 of the Notes to the Condensed Consolidated Financial Statements herein, our exposure to foreign currency rate risk would likely increase and could have a material impact on our Mexican income tax expense. From time to time, we may utilize short-term foreign currency derivatives at our subsidiaries and at the consolidated level as a means to manage these exposures.

The income tax expense of our South American subsidiaries is similarly impacted by the factors we discuss above. Such impact was not material in either the three months or nine months ended September 30, 2015 or 2014.

For Sempra Energy Consolidated, the impacts at Sempra Mexico related to the factors described above are as follows:

MEXICAN CURRENCY IMPACT ON INCOME TAXES AND RELATED ECONOMIC HEDGING ACTIVITY
(Dollars in millions)
		Three months ended				Nine months ended
		September 30,				September 30,
		2015		2014		2015		2014
Income tax benefit on currency exchange
	rate movement of monetary assets and liabilities	$	15	$	4	$	23	$	4
Translation of non-U.S. deferred income tax balances			6		5		10		5
Income tax expense on inflation			(1)		―		(1)		(1)
	Total impact included in Income Tax Benefit		20		9		32		8
After-tax losses on Mexican peso exchange rate
	instruments (included in Other Income, Net)		(3)		(4)		(4)		(4)
Net impacts on Sempra Energy Condensed
	Consolidated Statements of Operations	$	17	$	5	$	28	$	4

Equity Earnings, Net of Income Tax

For the three months and nine months ended September 30, 2015, equity earnings, net of income tax, increased by $20 million and $42 million, respectively, primarily due to:

§	start of operations in December 2014 of Los Ramones I, a pipeline which IEnova owns through GdC, a joint venture with PEMEX;

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

§	equity-related AFUDC for the Los Ramones Norte pipeline project, which IEnova is developing under a joint venture with PEMEX and affiliates of PEMEX.

On July 31, 2015, IEnova entered into an agreement to purchase PEMEX’s 50-percent interest in the GdC joint venture. The purchase transaction is expected to close in the fourth quarter of 2015. At closing, the joint venture will become a wholly owned, consolidated subsidiary of IEnova. See Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

Earnings

We discuss variations in earnings by segment above in “Segment Results.”

CAPITAL RESOURCES AND LIQUIDITY

We expect our cash flows from operations to fund a substantial portion of our capital expenditures and dividends. In addition, we may 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, at September 30, 2015, Sempra Energy, Sempra Global (the holding company for our subsidiaries not subject to California utility regulation) and the California Utilities each had five-year revolving credit facilities, expiring in 2017. At Sempra Energy and the California Utilities, the agreements were syndicated broadly among 24 different lenders and at Sempra Global, among 25 different lenders.

On October 13, 2015, Sempra Energy, Sempra Global and the California Utilities each entered into amended and restated five-year syndicated revolving credit agreements that supersede the previous agreements and expire in 2020. Prior to amendment, the credit facilities permitted revolving credit borrowings of up to $1.067 billion, $2.189 billion and $877 million at Sempra Energy, Sempra Global, and the California Utilities, respectively. The amended and restated credit facilities permit borrowings of up to $1 billion, $2.21 billion and $1 billion at Sempra Energy, Sempra Global, and the California Utilities, respectively. The new agreements are each syndicated broadly among 20 different lenders. No single lender has greater than a 7-percent share in any agreement. Sempra Energy, Sempra Global, and the California Utilities each have the right to increase, in one or more requests, the aggregate amount of the commitments by $250 million, $977.5 million, and $250 million, respectively.

The table below shows the amount of available funds, including available credit under the credit facilities in place at September 30, 2015:

AVAILABLE FUNDS AT SEPTEMBER 30, 2015
(Dollars in millions)
		Sempra Energy
		Consolidated		SDG&E		SoCalGas
Unrestricted cash and cash equivalents(1)		$	697	$	20	$	123
Available unused credit(2)			3,355		614		658
(1)	Amounts at Sempra Energy Consolidated include $525 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 September 30, 2015, borrowings on the shared line of credit at SDG&E and SoCalGas were limited to $658 million for each utility and a combined total of $877 million. SDG&E's available funds reflect commercial paper outstanding of $44 million supported by the line. Some of Sempra Energy's subsidiaries, primarily our foreign operations, have additional general purpose credit facilities, aggregating $945 million at September 30, 2015. Available unused credit on these lines totaled $485 million at September 30, 2015.

Sempra Energy Consolidated

We believe that these available funds, combined with cash flows from operations, distributions from equity method investments, proceeds of securities issuances, project financing and partnering in joint ventures will be adequate to fund operations, including to:

§	finance capital expenditures

§	meet liquidity requirements

§	fund shareholder dividends

§	fund new business acquisitions or start-ups

§	repay maturing long-term debt

In June 2015, SoCalGas issued $250 million of 1.55-percent and $350 million of 3.20-percent first mortgage bonds maturing in 2018 and 2025, respectively. In March 2015, Sempra Energy issued $500 million of 2.40-percent notes maturing in 2020. Also in March 2015, SDG&E issued $140 million of variable rate first mortgage bonds maturing in 2017 and $250 million of 1.914-percent amortizing first mortgage bonds maturing in 2022. In 2014, Sempra Energy and SoCalGas publicly offered and sold debt securities totaling $500 million and $750 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 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, changes in publicly traded debt securities and net changes to commercial paper borrowings on the Sempra Global and California Utilities credit facilities, the net increase in Sempra Energy Consolidated cash and cash equivalents at September 30, 2015 compared to December 31, 2014 of $127 million was primarily due to cash flows from operations, partially offset by common dividends paid and a decrease in foreign cash used to repay short-term debt. Proceeds received from Sempra Natural Gas’ sale of the remaining 625-MW block of its Mesquite Power plant were used to pay down commercial paper borrowings.

At September 30, 2015, our cash and cash equivalents held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated are $525 million. As we discuss in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” above, we no longer plan to repatriate current year 2015 earnings from our non-U.S. subsidiaries in Mexico due to IEnova’s pending acquisition of its joint venture partner’s 50-percent interest in Gasoductos de Chihuahua (GdC), which we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein. We plan to repatriate, in the future, current year earnings from certain of our non-U.S. subsidiaries in Peru, and accordingly, we are accruing tax expense on the current year earnings. Because this potential repatriation from Peru would only be from earnings since January 1, 2015, it does not change our current assertion that we intend to continue to indefinitely reinvest our cumulative undistributed non-U.S. earnings from prior years. Therefore, we do not intend to use these cumulative undistributed earnings as a source of funding for U.S. operations.

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 credit agreements more fully in Note 6 of the Notes to Condensed Consolidated Financial Statements herein.

Our short-term debt is primarily used to meet liquidity requirements, fund shareholder dividends, temporarily finance capital expenditures, and fund new business acquisitions or start-ups. Our corporate short-term, unsecured promissory notes, or commercial paper, were our primary sources of short-term debt funding in the first nine months of 2015. At our California Utilities, short-term debt is used to meet working capital needs and temporarily finance capital expenditures.

Master Limited Partnership

In June 2015, we announced that our Board of Directors authorized us to pursue the formation and initial public offering of a master limited partnership (MLP) to be called Sempra Partners, LP. Initially, the MLP is expected to own one or more of the following assets: an interest in a U.S. entity with contracts related to deliveries of LNG at the Energía Costa Azul regasification facility; interests in certain of Sempra Energy’s contracted renewable energy projects; or other assets with attributes attractive for inclusion in the MLP. Further, we expect to grant the MLP a right of first offer on certain LNG-related infrastructure projects, including our 50-percent interest in the first three trains of the Cameron natural gas liquefaction terminal and our 100-percent interest in the Cameron Interstate Pipeline, as well as our interests in certain contracted wind and solar projects. The anticipated offering would be subject to the final approval of our Board of Directors and market conditions.

In the second half of 2015, Sempra Energy submitted confidentially a Form S-1 to the Securities and Exchange Commission (SEC). The capital markets have been unfavorable for MLP initial public offerings since mid-2015. As a result of the uncertain markets, we have paused our efforts to move forward with an initial public offering and will reevaluate whether and when to pursue an MLP in mid-2016. There can be no assurance as to the timing or consummation of any MLP transaction. Our announcement of this plan did not, and this disclosure does not, constitute an offer to sell or the solicitation of an offer to buy any securities and shall not constitute an offer, solicitation or sale in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of that jurisdiction.

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.

In August 2015, SoCalGas declared $50 million in common stock dividends, which were paid on October 16, 2015. SoCalGas declared and paid $100 million in common stock dividends in 2014 and $50 million in 2013. 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 July 2015, SDG&E declared and paid $150 million in common stock dividends. In 2014, SDG&E declared and paid $200 million in common stock dividends. As a result of SDG&E’s large capital investment program over the past few years, SDG&E did not pay common stock dividends to Sempra Energy in 2013. However, due to the completion of construction of the Sunrise Powerlink transmission power line in June 2012, SDG&E resumed the declaration and payment of dividends on its common stock in 2014.

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. Primarily as a result of delays in the CPUC issuing final decisions on SDG&E’s ERRA-related filings, SDG&E’s ERRA balance is undercollected by $186 million at September 30, 2015 and $280 million at December 31, 2014. We discuss CPUC decisions in 2014 regarding rate changes resulting from the approved revenue requirement for ERRA costs in Note 14 of the Notes to Consolidated Financial Statements 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. As a result of warmer weather experienced last year and through the current year resulting in lower natural gas consumption compared to authorized levels, SoCalGas’ CFCA balance is undercollected by $365 million at September 30, 2015 and $266 million at December 31, 2014. SDG&E’s CFCA balance is $89 million undercollected at September 30, 2015 and $81 million undercollected at December 31, 2014.

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 $125 million and $50 million, respectively, of the December 31, 2014 CFCA balance in 2015 rates. In October 2015, SoCalGas and SDG&E filed their Annual Regulatory Account Balance updates to recover their projected December 31, 2015 CFCA undercollected balances of $417 million and $99 million, respectively, along with other regulatory account balances, in rates effective on January 1, 2016 upon CPUC approval.

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.

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. We expect IEnova’s pending acquisition of its joint venture partner’s 50-percent interest in GdC to be funded with a combination of debt and equity at IEnova. Sempra Global has committed to IEnova to provide approximately $1.325 billion of interim financing for the transaction. We expect to fund this commitment primarily with commercial paper under Sempra Global’s credit facility. If IEnova elects to borrow this money, it expects to repay all or a substantial portion of the loan with proceeds from a planned equity offering. IEnova is also arranging to receive bank commitments of up to $1.0 billion as an alternative source of capital to repay a portion of the interim financing from Sempra Global. Sempra Energy intends to participate in the planned equity offering with proceeds of dividends from IEnova that otherwise would be repatriated to the U.S. We discuss this pending acquisition from Sempra Mexico’s joint venture partner, PEMEX, further in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

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. In April 2015, Sempra Natural Gas invested $113 million in Rockies Express Pipeline LLC (Rockies Express) to repay project debt that matured in early 2015.

In April 2015, Sempra Natural Gas sold the remaining 625-MW block of the Mesquite Power plant, together with a related power sales contract, and received net cash proceeds of $347 million. The sale proceeds were used to pay down commercial paper at Sempra Energy. We discuss this sale further in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Natural Gas, through the Cameron LNG Holdings, LLC (Cameron LNG Holdings or Cameron LNG JV) joint venture, is developing a natural gas liquefaction export facility at the Cameron LNG JV terminal. The majority of the 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.

Some of Sempra Natural Gas’ long-term power sale contracts contain collateral requirements which require its affiliates and/or the counterparty to post cash or other acceptable collateral to the other party for exposure in excess of established thresholds. Sempra Natural Gas may be required to provide collateral when the fair value of the contract with our counterparty exceeds established thresholds. We have no collateral receivables or payables with our counterparties at September 30, 2015 pursuant to these requirements.

CASH FLOWS FROM OPERATING ACTIVITIES

CASH PROVIDED BY OPERATING ACTIVITIES
(Dollars in millions)
	Nine months ended September 30, 2015		2015 Change				Nine months ended September 30, 2014
Sempra Energy Consolidated	$	2,089	$	428	26	%	$	1,661
SDG&E		1,094		273	33			821
SoCalGas		690		94	16			596

Sempra Energy Consolidated

Cash provided by operating activities at Sempra Energy increased in 2015 primarily due to:

$140 million higher net income, adjusted for noncash items included in earnings, in 2015 compared to 2014, primarily due to improved operations at the California Utilities and Sempra South American Utilities, as well as higher pipeline earnings at Sempra Mexico, as we discuss in “Results of Operations” above;

$182 million net decrease in net undercollected regulatory balancing accounts in 2015 at the California Utilities (including long-term amounts included in regulatory assets) compared to a $243 million net increase in 2014. 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;

§	$41 million increase in inventories in 2015 compared to a $211 million increase in 2014. The 2014 increase was mainly due to higher storage volume and higher gas prices at SoCalGas; and

§	$117 million lower income tax payments in 2015; offset by

§	$130 million decrease in accounts payable in 2015 compared to a $52 million increase in 2014, primarily due to lower volumes and average cost of natural gas purchased at SoCalGas;

§	$144 million increase in greenhouse gas allowances ($93 million at SDG&E and $51 million at SoCalGas); and

§	$145 million decrease in accounts receivable in 2015 compared to a $243 million decrease in 2014.

SDG&E

Cash provided by operating activities at SDG&E increased in 2015 primarily due to:

§	$244 million decrease in net undercollected regulatory balancing accounts in 2015 (including long-term amounts included in regulatory assets) compared to a $38 million increase in 2014;

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

§	$70 million decrease in settlement payments and associated legal fees for wildfire claims in 2015 compared to 2014; offset by

§	$93 million increase in greenhouse gas allowances in 2015; and

§	$62 million income tax payments in 2015.

SoCalGas

Cash provided by operating activities at SoCalGas increased in 2015 primarily due to:

§	$10 million increase in inventories in 2015 compared to a $153 million increase in 2014. The 2014 increase was mainly due to higher storage volume and higher gas prices;

§	$62 million increase in net undercollected regulatory balancing accounts in 2015 (including long-term amounts included in regulatory assets) compared to a $205 million increase in 2014, primarily due to a lower increase in 2015 associated with the fixed cost balancing accounts; and

§	$29 million higher net income, adjusted for noncash items included in earnings, in 2015 compared to 2014, primarily due to improved operations; offset by

§	$191 million decrease in accounts payable in 2015 compared to a $14 million decrease in 2014. The decrease in 2015 was primarily due to lower volumes and average cost of natural gas purchased; and

§	$51 million increase in greenhouse gas allowances in 2015.

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

CONTRIBUTIONS TO PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
	Nine months ended September 30, 2015
			Other
	Pension		postretirement
	benefits		benefits
Sempra Energy Consolidated	$	27	$	3
SDG&E		2		―
SoCalGas		1		―

CASH FLOWS FROM INVESTING ACTIVITIES

CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
	Nine months ended						Nine months ended
	September 30, 2015		2015 Change				September 30, 2014
Sempra Energy Consolidated	$	(1,979)	$	(487)	(20)	%	$	(2,466)
SDG&E		(810)		14	2			(796)
SoCalGas		(1,196)		151	14			(1,045)

Sempra Energy Consolidated

Cash used in investing activities at Sempra Energy decreased in 2015 primarily due to:

§	$347 million of net proceeds received from Sempra Natural Gas’ sale of the remaining 625-MW block of its Mesquite Power plant;

$93 million decrease in capital expenditures, primarily due to completion of wind and solar projects at Sempra Renewables in 2014 and the Energía Sierra Juárez project at Sempra Mexico, and higher capital expenditures in 2014 for the Cameron liquefaction project prior to the formation of the Cameron LNG joint venture, offset by increased capital expenditures at the California Utilities in 2015; and

§	$131 million net decrease in advances to unconsolidated affiliates; offset by

§	in 2014, $66 million, net of $2 million cash sold, of proceeds received from the sale of a 50-percent equity interest in Copper Mountain Solar 3; and

§	in 2014, $24 million, net of $2 million cash sold, of proceeds received from the sale of a 50-percent equity interest in Energía Sierra Juárez.

SDG&E

Cash used in investing activities at SDG&E increased in 2015 due to:

§	$45 million increase in capital expenditures; offset by

$37 million decrease in Nuclear Decommissioning Trust assets in 2015 as a result of CPUC authorization to access trust funds for SONGS decommissioning costs incurred in 2013. We discuss the Nuclear Decommissioning Trust further in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.

SoCalGas

Cash used in investing activities at SoCalGas increased in 2015 due to:

§	$182 million increase in capital expenditures; offset by

§	$31 million lower advances to Sempra Energy.

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 FERC. However, in 2015, we expect to make capital expenditures and investments of approximately $4.8 billion. These expenditures include

§	$2.4 billion at the California Utilities for capital projects and plant improvements ($1.1 billion at SDG&E and $1.3 billion at SoCalGas)

§	$2.4 billion at our other subsidiaries for the 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’ 2015 planned capital expenditures and investments include

SDG&E

§	$700 million for improvements to natural gas, including pipeline safety, and electric generation and distribution systems

§	$400 million for improvements to electric transmission systems

§	$10 million for electric generation plants and equipment

SoCalGas

§	$1.1 billion for improvements to distribution, transmission and storage systems, and for pipeline safety

§	$210 million for advanced metering infrastructure

§	$30 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 2015, the expected capital expenditures and investments of approximately $2.4 billion (excluding amounts expended by joint ventures and net of anticipated project financing and joint venture structures as noted below) at our other subsidiaries include

Sempra South American Utilities

§	approximately $210 million for capital projects in South America (approximately $160 million and $50 million in Peru and Chile, respectively), primarily related to improvements to electric transmission and distribution systems

Sempra Mexico

§	approximately $1.7 billion in Mexico, net of project financing, including

□

approximately $1.3 billion for the 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. Following the acquisition, Sempra Mexico is expected to fund 100 percent of the joint venture’s projects, which excludes the Los Ramones Norte pipeline project

□	approximately $380 million for capital projects, including approximately $350 million for the development of the Sonora, Ojinaga, and San Isidro – Samalayuca pipeline projects, all developed solely by Sempra Mexico.

Sempra Renewables

§	approximately $170 million for the development of wind and solar renewable projects, including the Black Oak Getty wind project, Mesquite Solar 2, Mesquite Solar 3 and Copper Mountain Solar 4

Sempra Natural Gas

§	approximately $300 million for development of LNG and natural gas transportation projects, including

□	approximately $160 million equity investment in Rockies Express

□	approximately $50 million capitalized interest related to our investment in the Cameron LNG JV project, and $40 million for development of the Cameron Interstate Pipeline

Parent and Other

§	approximately $50 million primarily related to the build-to-suit lease for Sempra Energy’s new headquarters

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)
	Nine months ended				Nine months ended
	September 30, 2015		2015 Change		September 30, 2014
Sempra Energy Consolidated	$	29	$	(543)	$	572
SDG&E		(272)		(253)		(19)
SoCalGas		544		97		447

Sempra Energy Consolidated

Cash provided by financing activities at Sempra Energy decreased in 2015 primarily due to:

$1 billion lower issuances of debt, including a decrease in commercial paper and other short-term debt borrowings with maturities greater than 90 days of $929 million ($460 million in 2015 compared to $1.4 billion in 2014), and lower issuances of long-term debt of $76 million ($1.6 billion in 2015 compared to $1.7 billion in 2014); and

§	$201 million decrease in short-term debt in 2015 compared to a $111 million decrease in 2014; offset by

$529 million lower payments on debt, including lower payments of long-term debt of $710 million ($422 million in 2015 compared to $1.1 billion in 2014), offset by higher payments of commercial paper and other short-term debt with maturities greater than 90 days of $181 million ($894 million in 2015 compared to $713 million in 2014).

SDG&E

Cash used in financing activities at SDG&E increased in 2015 primarily due to:

§	$272 million higher payments on long-term debt in 2015;

§	$150 million common dividends paid in 2015; and

§	$202 million decrease in short-term debt in 2015 compared to a $59 million decrease in 2014; offset by

§	$288 million higher issuances of long-term debt in 2015.

SoCalGas

Cash provided by financing activities at SoCalGas increased in 2015 primarily due to:

§	$250 million payments of long-term debt in 2014; offset by

§	$148 million lower issuances of long-term debt in 2015.

COMMITMENTS

We discuss significant changes to contractual commitments at Sempra Energy, SDG&E and SoCalGas in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

CREDIT RATINGS

The credit ratings of Sempra Energy, SDG&E and SoCalGas remained at investment grade levels during the first nine months of 2015. 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” 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 in various sections of this report and below. We discuss certain regulatory matters below and in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein and Notes 13 and 14 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 deductions, discussed below. The settlement agreements are with eight of eleven intervening parties. For SoCalGas, the settlement proposes a reduction of $133 million compared to its original request, or a total revenue requirement in 2016 of $2.219 billion. This is an increase of $122 million or 6 percent over 2015. For SDG&E, the settlement proposes a reduction of $100 million compared to its original request (as revised), or a total revenue requirement in 2016 of $1.811 billion. This is an increase of $17 million, or one percent over 2015. The filed settlement agreements also call for attrition adjustments of 3.5 percent for both 2017 and 2018. 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.

We anticipate all matters to be resolved with the final resolution of the 2016 GRC. We expect the CPUC to issue a draft decision in the proceeding in the first 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, SoCalGas, SDG&E, Pacific Gas and Electric Company (PG&E) and Southwest Gas 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 General Rate Case proceedings concluded in 2013. Similarly, these costs are not included in our 2016 General Rate Case filings.

In June 2014, the CPUC issued a final decision in the Triennial Cost Allocation Proceeding (TCAP) 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 for which SoCalGas was disallowed recovery. After taking the amounts disallowed for recovery into consideration, as of September 30, 2015, SDG&E and SoCalGas have recorded PSEP costs of $7 million and $153 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. 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. In August 2015, the ORA, The Utility Reform Network (TURN), and the Southern California Generation Coalition (SCGC) served testimony to the CPUC that recommended disallowances related to completed projects, as well as facilities build-out costs, de-scoped projects, and project management and consulting costs. The ORA’s recommended disallowance would result in an $11.1 million decrease to SoCalGas’ original recovery application of $26.8 million, to $15.7 million. The disallowance recommended by TURN and SCGC would result in a $2.3 million decrease to SoCalGas’ original recovery application of $26.8 million, to $24.5 million. In August 2015, the California Utilities also provided testimony to the CPUC, contesting the proposed disallowances. 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. 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 November 2014, the CPUC denied the ORA and TURN request for rehearing of the decision adopting the PSEP. In December 2014, the ORA and TURN sought rehearing of the CPUC’s decision on rehearing. In late December 2014, SoCalGas and SDG&E filed their opposition to this second application for rehearing, and are continuing to implement PSEP in accordance with the June 2014 CPUC decision. In March 2015, the CPUC issued a decision denying ORA’s and TURN’s second request for rehearing but keeping the record in the proceeding open to admit additional evidence on the limited issue of pressure testing of pipelines installed between January 1, 1956 and July 1, 1961. As part of this review, the CPUC will allow parties to submit additional evidence relevant to this narrow issue to ensure a complete record, with no additional discovery allowed. The ORA and TURN filed their responses on May 1, 2015. In October 2015, the CPUC issued a proposed 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 pipeline. At September 30, 2015, SoCalGas and SDG&E estimate amounts related to these costs to be approximately $5 million and $3 million, respectively.

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, enacted in October 2013, 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. SB 291 requires the CPUC to implement the enforcement program for gas safety by July 1, 2014 and for electric safety by January 1, 2015. 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. In December 2014, the CPUC adopted an electric safety enforcement program whereby electric utilities may be cited by CPUC staff for violations of the CPUC’s safety requirements or federal standards.

In December 2011, the CPUC adopted a gas safety citation program whereby natural gas distribution companies can be cited by CPUC staff for violations of the CPUC’s safety standards. In September 2013, the CPUC’s safety and enforcement division issued its Standard Operating Procedures setting forth its principles and management process for the natural gas safety citation program.

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 in 2015.

SDG&E Matters

2007 Wildfire Litigation

In regard to the 2007 wildfire litigation, SDG&E’s payments for claims settlements plus funds estimated to be required for settlement of outstanding claims and legal fees have exceeded its liability insurance coverage and amounts recovered from third parties. However, SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of the reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and amounts recovered from third parties. Consequently, Sempra Energy and SDG&E expect no significant earnings impact from the resolution of the remaining wildfire claims. At September 30, 2015, Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets include assets of $362 million in Other Regulatory Assets (long-term), of which $359 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.

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 will record a charge against earnings. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated, at September 30, 2015, 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 Note 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 the Notes to Condensed Consolidated Financial Statements herein as follows:

In Note 9:

§	SONGS Outage and Retirement

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

§	Settlement with Nuclear Electric Insurance Limited (NEIL)

§	Nuclear Regulatory Commission Proceedings

§	Nuclear Decommissioning and Funding

§	Nuclear Decommissioning Trusts

In Note 11:

§	Legal Proceedings – SDG&E – Lawsuit Against Mitsubishi Heavy Industries, Ltd.

§	Nuclear Insurance

§	U.S. Department of Energy (DOE) Nuclear Fuel Disposal

We also discuss SONGS 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 are in dispute regarding whether all conditions precedent in the contribution agreement have been achieved by the developer of the project. As a result, SDG&E has not made the investment, and the project developer and SDG&E are in dispute regarding SDG&E’s contractual obligation to invest in the project, as we discuss 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 February 2014, SDG&E filed comprehensive proposals with the CPUC that provide a roadmap to reforming electric residential rate design beginning in 2015 and continuing through 2018, consistent with the provisions of AB 327. In July 2015, the CPUC adopted a revised Administrative Law Judge (ALJ)-proposed decision that establishes comprehensive reform and a framework for rates that are more transparent, fair and sustainable. The revised ALJ-proposed 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 would be reduced from four to three in 2015 and to two in 2016. The rate differential between the highest and lowest tiers would be reduced from approximately 2.4 times to 2.18 times this year, down to 1.25 times by 2019. The revised ALJ-proposed decision also directs the utilities to pursue expanded time of use (TOU) rates and implements a super user electric (SUE) surcharge in 2017 for usage that exceeds average customer usage by approximately 400 percent. The adopted 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 that require 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 power they generate that is fed back to the utility’s power grid during times when the customer’s generation exceeds their own energy usage. In addition, if a NEM customer net generates any electricity over the annual measurement period, they receive compensation at a rate equal to a wholesale energy price.

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. If the CPUC fails to reform SDG&E’s rate structures to allow it to recover costs associated with the services provided to NEM customers, such failure could have a material adverse effect on SDG&E’s business, cash flows, financial condition, results of operations and/or prospects. On August 3, 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. A CPUC decision should be issued by the end of 2015. SDG&E would implement the successor tariff by the earlier of July 1, 2017 or when SDG&E reaches its existing NEM program limit, which may occur as early as the second half of 2016. For additional discussion, see “Risk Factors” in the Annual Report.

California Senate Bill 350

SB 350, recently signed into law, creates new requirements for the utilities in the areas of renewable procurements, energy efficiency, and electric vehicle (EV) infrastructure. Specifically, the bill raises the state mandated renewable portfolio standard to 50 percent by 2030. The new law 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. The law also enhances focus on improving efficiency in older buildings. We expect to meet the higher renewable portfolio standard and are supportive of greater infrastructure development to support electric vehicle charging. Our Electric Vehicle Charging Program, which we discuss in Note 10, does not include potential additional opportunities associated with SB 350.

SoCalGas Matters

Distributed Energy Resources Services (DERS) Tariff

In October 2015, the CPUC approved SoCalGas’ application to offer the DERS Tariff to facilitate the adoption and use of combined heat and power (CHP) energy systems for its customers. The DERS Tariff service allows SoCalGas to install and own CHP energy systems up to 20 MW at customer facilities, and SoCalGas may also operate the systems. DERS systems must meet the efficiency, greenhouse gas and emission standards of the CPUC Self Generation Incentive Program (SGIP). The DERS Tariff is authorized for ten years from the issuance date of the decision, and all risks and costs associated with the DERS Tariff shall be borne by shareholders and DERS customers.

Triennial Cost Allocation Proceeding (TCAP) – Adoption of Seasonal Factors

The TCAP decision issued by the CPUC in June 2014 requires SoCalGas to recognize interim period revenue for its core natural gas customers by applying seasonal factors to its annual authorized revenue beginning in 2015, instead of recognizing such revenue ratably over the year as was previously required. While this “seasonalization” will not impact SoCalGas’ cash flows or total calendar year revenue and earnings for 2015 or beyond, and does not change the annual total authorized revenue or our earnings from that revenue, it will cause variability in revenue and earnings from quarter to quarter. We expect that core natural gas customer authorized revenue recognized in the first and fourth quarters of each year will be higher (approximately 34 percent in the first quarter and 29 percent in the fourth quarter) than that recognized in the second and third quarters of each year (approximately 21 percent in the second quarter and 16 percent in the third quarter). This seasonalization resulted in a decrease to Sempra Energy’s and SoCalGas’ revenue and earnings for the three-month period ended September 30, 2015 of $158 million and $113 million, respectively, and a decrease to Sempra Energy’s and SoCalGas’ revenue and earnings for the nine-month period ended September 30, 2015 of $67 million and $48 million, respectively, compared to the same periods in 2014. Also as a result of seasonalization, beginning in 2015, substantially all of SoCalGas’ annual earnings will be recognized in the first and fourth quarters of the year. The reduced revenue expected to be recognized in the second and third quarters of each year could result in losses for SoCalGas in these quarters, as was the case in the current three-month period ended September 30, 2015, in which SoCalGas incurred losses of $8 million.

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 the “Capital Resources and Liquidity” and “Factors Influencing Future Performance” sections of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

Sempra South American Utilities

Overview

In connection with the increase in 2011 of our interests in our two utilities in South America, Chilquinta Energía and Luz del Sur, Sempra Energy has $750 million in goodwill on its Condensed Consolidated Balance Sheet at September 30, 2015. Goodwill is subject to impairment testing, annually and under other potential circumstances, which may cause its fair value to vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions.

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 are scheduled to be completed, with tariff adjustments also going into effect, in January 2016 for sub-transmission, and for distribution 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 in Peru and revenues are based on rates set by the Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería). 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 the Annual Report.

In September 2014, tax reform legislation was passed in Chile. The main amendments established in the tax reform include, among others, a gradual increase in the corporate income tax rate and the introduction of two options to pay the secondary tax (shareholder tax) on corporate profits (either immediate payment of tax or deferment of tax until earnings are distributed) with different impacts to the total income tax burden. We discuss this tax reform 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.

In December 2014, the Peruvian government passed a tax reform law. Among other changes, the new law gradually reduces the 30 percent corporate tax rate in 2014 to 26 percent by 2019 with an offsetting increase in the withholding tax rate on dividends. We discuss this tax reform 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.

Field, technical and administrative employees at Luz del Sur are represented by the Unified Trade Union of Electricity Workers of Lima and Callao, and the Trade Union of Employees of Electrolima. A collective bargaining agreement was signed in February 2015 with both of these trade unions covering these employees and was also extended to 149 nonrepresented employees. It covers wages, working conditions and other benefit plans, and is in effect from January 1, 2015 through December 31, 2015.

Santa Teresa

Luz del Sur began commercial operation of Santa Teresa, a 100-MW hydroelectric power plant in Peru’s Cusco region, in September 2015.

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 transmission lines will extend 150 miles, and we estimate the projects will cost approximately $180 million in total and be completed by the end of 2015 and 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.

Sempra South American Utilities has a U.S. dollar-denominated loan to Eletrans S.A. totaling $65 million at September 30, 2015 to provide project financing for the construction of transmission lines. Eletrans S.A. is an affiliate of Chilquinta Energía.

The projects will be financed by the joint venture partners. 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, and partnering in joint ventures.

IEnova and PEMEX are 50-50 partners in the joint venture Gasoductos de Chihuahua (GdC). In July 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. GdC develops and operates energy infrastructure in Mexico. The assets involved in the acquisition include three natural gas pipelines, an ethane pipeline, and a liquid petroleum gas pipeline and associated storage terminal. All the assets are covered by long-term contracts. The transaction excludes the Los Ramones Norte pipeline that IEnova will continue to develop under a joint venture with PEMEX at the existing holding company for the project, through which IEnova’s interest in the project will remain at the current 25 percent. IEnova shareholders approved the transaction in September 2015. The transaction is subject to satisfactory completion of the Mexican anti-trust review and other customary closing conditions and is expected to close by the end of 2015.

We discuss the financing of the transaction, including Sempra Global’s bridge loan commitment, IEnova’s planned equity offering to repay such loan, and the arrangement of bank commitments above, under “Capital Resources and Liquidity – Sempra Mexico.” After financing at the IEnova level, we expect the acquisition to be accretive to Sempra Energy’s diluted earnings per share, based on the joint venture’s strong historical performance. We expect the transaction to have additional benefits, including an ongoing relationship with PEMEX for joint development of new projects in the future; opportunities for asset optimization and expansion into areas such as the transportation and storage of refined products; and a larger platform and presence in Mexico to participate in energy sector reform.

We discuss IEnova’s credit facilities in Note 6 of the Notes to Condensed Consolidated Financial Statements herein.

We discuss the impact of Mexican tax reform 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.

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 December 2012, through its GdC joint venture, IEnova executed an ethane transportation services agreement with PEMEX to construct and operate an approximately 140-mile pipeline (Ethane pipeline) to transport ethane from Tabasco, Mexico to Veracruz, Mexico. We estimate it will cost approximately $380 million. The first and second sections of the pipeline were completed in January and July 2015, respectively, and we expect to complete the remaining section in 2015. PEMEX has fully contracted the capacity under a 21-year contract denominated in U.S. dollars. Upon closing of the acquisition of the GdC joint venture, IEnova will own 100 percent of the Ethane pipeline.

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 275 miles and two compression stations, which will connect with the first phase of Los Ramones and run to the vicinity of San Luis Potosi, with an estimated cost of approximately $1.3 billion to $1.5 billion. The GdC joint venture has a 50-percent interest in the project. Upon closing of the acquisition of the GdC joint venture, IEnova will continue to develop the Los Ramones Norte project under a joint venture with PEMEX at the existing holding company for the project through which IEnova’s interest in the project will remain at the current 25 percent. We expect expenditures for the project to be funded by the joint venture’s cash flows from operations and project financing, plus additional contributions from its partners. We expect the pipeline to begin operations in the first half of 2016. The pipeline’s capacity is fully contracted under a 25-year transportation services agreement with PEMEX denominated in Mexican pesos, with a contract rate based on the U.S. dollar investment, adjusted annually for inflation and fluctuation of the exchange rate.

Sempra Mexico has loans to an affiliate of its joint venture with PEMEX totaling $86 million at September 30, 2015 to finance the Los Ramones Norte pipeline project.

In December 2014, Sempra Mexico entered into the Ojinaga pipeline natural gas transportation services agreement with CFE for a 25-year term, denominated in U.S. dollars. CFE contracted 100 percent of the transport capacity of the Ojinaga pipeline, equal to 1.4 billion cubic feet (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 the San Isidro - Samalayuca pipeline (San Isidro pipeline) natural gas transportation services agreement with CFE for a 25-year term, denominated in U.S. dollars. CFE contracted 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.

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.

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 and negotiating suitable construction contracts. 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, potentially, other forms of equity sales. 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 will complete 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.

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; it is being developed in multiple phases as power sales become contracted. Copper Mountain Solar is comprised of four separate projects.

Copper Mountain Solar 1 is a 58-MW photovoltaic generation facility currently in operation, which is fully contracted for 20 years to PG&E.

Copper Mountain Solar 2 is divided into two phases totaling 150 MW. The 92-MW first phase was placed in service in November 2012 and the 58-MW second phase was placed in service in April 2015. PG&E has contracted for all of the solar power at Copper Mountain Solar 2 for 25 years. In July 2013, we completed the sale of 50 percent of our equity in Copper Mountain Solar 2 to Consolidated Edison Development (Con Edison Development).

Copper Mountain Solar 3 achieved full commercial operation in April 2015, and totals 250 MW. The cities of Los Angeles and Burbank have contracted for all of the solar power at Copper Mountain Solar 3 for 20 years. In addition to solar power, the power sales agreement provides the cities of Los Angeles and Burbank the option to purchase the Copper Mountain Solar 3 facility at years 10, 15 and 20 of the contract term, or upon earlier termination of the agreement. In March 2014, we completed the sale of 50 percent of our equity in Copper Mountain Solar 3 to Con Edison Development, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

In July 2014, Sempra Renewables signed a 20-year power sale agreement with Southern California Edison Company (Edison) for all of the solar power from Copper Mountain Solar 4 beginning in 2020. The CPUC approved the power sale agreement 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 Con Edison Development. 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. The power sale agreement is subject to approval by the CPUC. In July 2015, Sempra Renewables signed a 25-year power sale agreement 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. We expect the second and third phases of Mesquite Solar to be in service by the end of 2016.

Sempra Natural Gas

Mesquite Power Natural Gas-Fired Plant

In February 2013, Sempra Natural Gas completed the sale of one 625-MW block of its Mesquite Power plant to the Salt River Project Agricultural Improvement and Power District for $371 million in cash.

On April 9, 2015, Sempra Natural Gas sold the remaining 625-MW block of the Mesquite Power plant, together with the related power sales contract, for net cash proceeds of $347 million. We discuss this sale further in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

Rockies Express

Sempra Natural Gas owns a 25-percent interest in Rockies Express Pipeline LLC (Rockies Express), a partnership that operates a natural gas pipeline, the Rockies Express pipeline (REX), which links the Rocky Mountains region to the upper Midwest and the eastern United States. All of REX’s original capacity sales provide for west-to-east service. Sempra Natural Gas has an agreement for such capacity on REX through November 2019. The capacity costs are offset by revenues from releases of the capacity contracted to third parties. Certain capacity release commitments totaling $22 million concluded during 2013. Contracting activity related to that capacity has not been sufficient to offset all of our capacity payments to Rockies Express.

In November 2013, FERC issued a decision ruling that east-to-west service offerings within a single REX rate zone would not result in potential rate reductions under provisions in the original customers’ west-to-east contracts (“most favored nation” provisions). In December 2013, certain west-to-east customers sought rehearing of that decision. In 2014, Rockies Express reached settlements with three west-to-east customers, with one customer continuing to seek rehearing. The triggering of these provisions would result in significantly reduced revenue to REX from these west-to-east contracts.

In April 2014, prior to the launching of an open season, Rockies Express had secured binding financial commitments with four shippers totaling 1.2 Bcf per day of capacity for east-to-west transportation services for a term of 20 years originating at or near Clarington, Ohio. In February 2015, Rockies Express received FERC approval for the project. Rockies Express began construction on the project, and the capacity went into service on August 1, 2015. In June 2014, Rockies Express finished constructing the Seneca Lateral, an initial 0.25 Bcf per day capacity project that connects natural gas production sources in Ohio to REX. The lateral’s capability was further expanded to 0.6 Bcf per day of capacity in January 2015. The lateral is fully contracted through September 2021.

In March 2015, Rockies Express requested FERC approval of the Zone 3 Capacity Enhancement Project. The project is an expansion of REX’s east-to-west capability of 0.8 Bcf per day. Rockies Express conducted both a non-binding and a binding open season for service on the Zone 3 Capacity Enhancement Project and secured binding financial commitments with six Appalachian shippers totaling 0.7 Bcf per day of capacity for east-to-west transportation services for a term of 15 years originating at or near Clarington, Ohio. We expect the project to be in-service in the fourth quarter of 2016. This expansion, with an estimated cost of approximately $530 million, will require additional capital investment by the partners and is subject to regulatory approval. When completed, REX’s total east-to-west capability within Zone 3 will be 2.6 Bcf per day.

In April 2015, Sempra Natural Gas invested $113 million in Rockies Express to repay project debt that matured in early 2015.

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 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 Bay Gas and Mississippi Hub, replacement sales contract rates could 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. In April 2015, we received authorization from FERC to begin construction on the LA Storage project. In an order issued on May 7, 2015, FERC approved our request to extend the construction permit for the project for an additional two years, so that it now will expire in June 2017, absent an additional extension. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage pipeline, that is uncontracted.

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 book value is in excess of the fair value, we would record a noncash impairment charge. The book value of our long-lived natural gas storage assets at September 30, 2015 is $1.5 billion.

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 may, over the long term, develop additional storage capacity at its facilities.

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 76 percent of the project and ProLiance Transportation LLC owns the remaining 24 percent. The project’s location provides access to several LNG facilities in the area.

Cameron Liquefaction Project

The Cameron LNG, LLC regasification terminal in Hackberry, Louisiana, 100-percent owned by Sempra Natural Gas until October 1, 2014, is capable of processing 1.5 Bcf of natural gas per day. The terminal 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. 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.

In August 2014, Sempra Energy and three project partners provided their respective final investment decision with regard to the Cameron LNG Holdings, LLC (Cameron LNG Holdings or Cameron LNG JV) joint venture for the development, construction and operation of a natural gas liquefaction export facility at the Cameron LNG, LLC terminal. On October 1, 2014, we contributed our share of equity to the joint venture through the contribution of Cameron LNG, LLC. Beginning from the October 1, 2014 joint venture effective date, Cameron LNG, LLC is no longer wholly owned, and Sempra Natural Gas accounts for its investment in the joint venture under the equity method. 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 current project, 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. 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 our 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 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. Cameron LNG JV is also pursuing the permitting to expand the current configuration from the current three liquefaction trains. 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 one additional full containment LNG storage tank; a fourth tank was permitted with the base liquefaction project but not built. In February 2015, Cameron LNG JV filed the DOE FTA application and the pre-filing application at FERC for the two additional trains and 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. 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. In addition, 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, securing all necessary permits and approvals, obtaining financing, reaching a final investment decision and other factors associated with the potential investment. See the “Risk Factors” section of our 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 been meeting with potential customers and continue to see long-term demand for LNG supplies beginning in the 2020 to 2023 time frame. Total expenditures on LNG liquefaction development in the nine months ended September 30, 2015 were $24 million, including capitalized costs of $13 million (pretax). After-tax LNG development costs expensed in the three months and nine months ended September 30, 2015 were $2 million and $7 million, respectively.

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 June 2015, Sempra Natural Gas entered into a non-binding MOU with an affiliate of Woodside Petroleum Ltd. (Woodside) to commence discussions and assessments for the potential development of the proposed Port Arthur LNG liquefaction project. The non-binding MOU is the initial step for Sempra Natural Gas and Woodside to explore this opportunity and undertake due diligence for the potential development of the Port Arthur LNG liquefaction project. Any decision to proceed with a binding agreement between Woodside and Sempra Natural Gas in relation to the potential development of the project, including the establishment of any joint venture or partnership between Sempra Natural Gas and Woodside, is contingent upon completing project assessments and achieving other necessary internal and external approvals for each party.

Development of the Port Arthur LNG liquefaction project is subject to a number of risks and uncertainties, including completing the required commercial agreements, securing all necessary permits and approvals, obtaining financing and incentives, reaching a final investment decision and other factors associated with the potential investment. See the “Risk Factors” section of our 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.”

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 $71 million at September 30, 2015 reflects remaining distributions expected to be received from the partnership as it is dissolved. The amount of distributions 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. Moreover, the dollar may fluctuate significantly compared to some foreign currencies, especially in Mexico and South America where we have significant operations. We discuss foreign currency rate risk further under “Foreign Currency Rate Risk” in Item 3. “Quantitative and Qualitative Disclosures About Market Risk” below. North American natural gas prices, when in decline, negatively affect profitability at Sempra Natural Gas. Also, a reduction in projected global demand for LNG could result in increased competition among those working on projects in an environment of declining LNG demand, such as the Sempra Energy-sponsored export initiatives. For a discussion of these risks and other risks involving changing commodity prices, see “Risk Factors” in the Annual Report.

In July 2010, federal legislation to reform financial markets was enacted that significantly alters how over-the-counter (OTC) derivatives are regulated, which may impact all of our businesses. The law increased regulatory oversight and transparency requirements of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the U.S. Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits, the latter of which is pending final approval. The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users. These requirements could cause our OTC transactions to be more costly and have a material adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products, they could limit the effectiveness and extent of our hedging programs, because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to mitigate and may be restricted on the size of our hedging program.

Our future performance depends substantially on the timing and success of our business development efforts and our construction, maintenance and capital projects. We discuss this and additional matters that could affect our future performance in Notes 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein, in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, and in “Risk Factors” in the Annual Report.

LITIGATION

We describe legal proceedings which could adversely affect our future performance in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We view certain accounting policies as critical because their application is the most relevant, judgmental, and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates. We discuss these accounting policies in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

NEW ACCOUNTING STANDARDS

We discuss the relevant pronouncements that have recently 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.

INTEREST RATE RISK

The table below shows the nominal amount and the one-year Value at Risk (VaR) for long-term debt at September 30, 2015 and December 31, 2014:

NOMINAL AMOUNT AND ONE-YEAR VALUE AT RISK OF LONG-TERM DEBT(1)
(Dollars in millions)
		Sempra Energy
		Consolidated				SDG&E				SoCalGas
		Nominal		One-year		Nominal		One-year		Nominal		One-year
		debt		VaR(2)		debt		VaR(2)		debt		VaR(2)
At September 30, 2015:
	California Utilities fixed-rate	$	6,612	$	772	$	4,100	$	499	$	2,512	$	274
	California Utilities variable-rate		457		10		457		10		―		―
	All other, fixed-rate and variable-rate		6,272		377		―		―		―		―
At December 31, 2014:
	California Utilities fixed-rate	$	6,049	$	502	$	4,136	$	341	$	1,913	$	161
	California Utilities variable-rate		325		13		325		13		―		―
	All other, fixed-rate and variable-rate		5,973		306		―		―		―		―
(1)	Excluding capital lease obligations, build-to-suit lease and interest rate swaps, and before reductions/increases for unamortized discount/premium.
(2)	After the effects 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 RATE RISK

We discuss our foreign currency exposure at our current Mexican subsidiaries, as well as at GdC, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes – Foreign Currency Exchange Rate and Inflation Impact on Income Taxes and Related Economic Hedging Activity” 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 September 30, 2015, there were no significant changes to our exposure to foreign currency rate risk since December 31, 2014. After the closing of our pending acquisition of the 50-percent interest in GdC, 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, reducing the foreign currency rate risk related to their operations.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Sempra Energy, SDG&E and SoCalGas have designed and maintain disclosure controls and procedures to ensure that information required to be disclosed in their respective reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the management of each company, including each respective Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, the management of each company recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives; therefore, the management of each company applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures.

Under the supervision and with the participation of management, including the Chief Executive Officers and Chief Financial Officers of Sempra Energy, SDG&E and SoCalGas, each company evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of September 30, 2015, 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 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, 2014.

ITEM 6. EXHIBITS

The following exhibits relate to each registrant as indicated.

	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 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: November 3, 2015	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: November 3, 2015	By: /s/ Bruce A. Folkmann
	Bruce A. Folkmann Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

Southern California Gas Company:

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SOUTHERN CALIFORNIA GAS COMPANY, (Registrant)

Date: November 3, 2015	By: /s/ Bruce A. Folkmann
	Bruce A. Folkmann Vice President, Controller, Chief Financial Officer and Chief Accounting Officer