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, 2012
	or
[   ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from		to
Commission File No.		Exact Name of Registrants as Specified in their Charters, Address and Telephone Number	States of Incorporation		I.R.S. Employer Identification Nos.		Former name, former address and former fiscal year, if changed since last report
1-14201		SEMPRA ENERGY	California		33-0732627		No change
		101 Ash Street
		San Diego, California 92101
		(619)696-2000
1-03779		SAN DIEGO GAS & ELECTRIC COMPANY	California		95-1184800		No change
		8326 Century Park Court
		San Diego, California 92123
		(619)696-2000
1-01402		SOUTHERN CALIFORNIA GAS COMPANY	California		95-1240705		No change
		555 West Fifth Street
		Los Angeles, California 90013
		(213)244-1200
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
			Yes	X		No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Sempra Energy				Yes	X		No
San Diego Gas & Electric Company				Yes	X		No
Southern California Gas Company				Yes	X		No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
	Large accelerated filer		Accelerated filer			Non-accelerated filer		Smaller reporting company
Sempra Energy	[  X  ]		[      ]			[       ]		[      ]
San Diego Gas & Electric Company	[       ]		[      ]			[  X  ]		[      ]
Southern California Gas Company	[       ]		[      ]			[  X  ]		[      ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Sempra Energy				Yes			No		X
San Diego Gas & Electric Company				Yes			No		X
Southern California Gas Company				Yes			No		X
Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.
Common stock outstanding on November 1, 2012:
Sempra Energy		241,851,686 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	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	73
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	111
Item 4.	Controls and Procedures	112
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	113
Item 1A.	Risk Factors	113
Item 6.	Exhibits	115
Signatures		117

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,” “contemplates,” “intends,” “depends,” “should,” “could,” “would,” “will,” “may,” “potential,” “target,” “pursue,” “goals,” or similar expressions, or when we discuss our guidance, strategy, plans, goals, 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 by the California Public Utilities Commission, California State Legislature, Federal Energy Regulatory Commission, U.S. Department of Energy, Nuclear Regulatory Commission, California Energy Commission, California Air Resources Board, and other regulatory, governmental and environmental bodies in the United States and other countries in which we operate;

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

§   inflation, interest and exchange rates;

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

§   the timing and success of business development efforts and construction, maintenance and capital projects, including risks inherent in the ability to obtain, and the timing of granting of, permits, licenses, certificates and other authorizations;

§   energy markets, including the timing and extent of changes and volatility in commodity prices;

§   the availability of electric power, natural gas and liquefied natural gas, including disruptions caused by failures in the North American transmission grid, pipeline explosions and equipment failures;

§   weather conditions, natural disasters, catastrophic accidents, and conservation efforts;

§   risks inherent in nuclear power generation 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 generation facility due to an extended outage, and increased regulatory oversight;

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

§   wars, terrorist attacks and cybersecurity threats;

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

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

§   the status of deregulation of retail natural gas and electricity delivery;

§   the inability or determination not to enter into long-term supply and sales agreements or long-term firm capacity agreements;

§   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 in this report and in our Annual Report on Form 10-K and other reports that we file with the Securities and Exchange Commission.

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts)
		Three months ended September 30,				Nine months ended September 30,
		2012		2011(1)		2012		2011(1)
		(unaudited)
REVENUES
Utilities		$	2,170	$	2,065	$	6,099	$	5,933
Energy-related businesses			337		511		880		1,499
Total revenues			2,507		2,576		6,979		7,432
EXPENSES AND OTHER INCOME
Utilities:
Cost of natural gas			(212)		(322)		(864)		(1,367)
Cost of electric fuel and purchased power			(515)		(408)		(1,252)		(976)
Energy-related businesses:
Cost of natural gas, electric fuel and purchased power			(136)		(252)		(346)		(694)
Other cost of sales			(43)		(68)		(117)		(123)
Operation and maintenance			(732)		(691)		(2,123)		(2,003)
Depreciation and amortization			(280)		(251)		(803)		(729)
Franchise fees and other taxes			(89)		(84)		(264)		(259)
Equity (losses) earnings, before income tax:
Rockies Express Pipeline LLC			(87)		10		(366)		29
Other			(7)		(22)		(9)		(33)
Remeasurement of equity method investments			―		―		―		277
Other income, net			44		12		137		86
Interest income			5		6		14		21
Interest expense			(126)		(118)		(352)		(344)
Income before income taxes and equity earnings
of certain unconsolidated subsidiaries			329		388		634		1,317
Income tax expense			(49)		(75)		(48)		(289)
Equity earnings, net of income tax			10		6		29		45
Net income			290		319		615		1,073
Earnings attributable to noncontrolling interests			(20)		(29)		(44)		(21)
Preferred dividends of subsidiaries			(2)		(1)		(5)		(6)
Earnings		$	268	$	289	$	566	$	1,046
Basic earnings per common share		$	1.11	$	1.21	$	2.35	$	4.36
Weighted-average number of shares outstanding, basic (thousands)			241,689		239,545		241,133		239,693
Diluted earnings per common share		$	1.09	$	1.20	$	2.31	$	4.32
Weighted-average number of shares outstanding, diluted (thousands)			245,802		241,880		245,013		241,955
Dividends declared per share of common stock		$	0.60	$	0.48	$	1.80	$	1.44
(1)	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
		Three months ended September 30,
		2012						2011(1)
		(unaudited)
				Non-						Non-
		Sempra		controlling				Sempra		controlling
		Energy		Interests		Total		Energy		Interests		Total
Net income		$	270	$	20	$	290	$	290	$	29	$	319
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments			80		8		88		(132)		(7)		(139)
Net actuarial (loss) gain			(10)		―		(10)		1		―		1
Financial instruments			(3)		(4)		(7)		(14)		(25)		(39)
Total other comprehensive income (loss)			67		4		71		(145)		(32)		(177)
Total comprehensive income (loss)			337		24		361		145		(3)		142
Preferred dividends of subsidiaries			(2)		―		(2)		(1)		―		(1)
Total comprehensive income (loss), after preferred
dividends of subsidiaries		$	335	$	24	$	359	$	144	$	(3)	$	141
		Nine months ended September 30,
		2012						2011(1)
		(unaudited)
				Non-						Non-
		Sempra		controlling				Sempra		controlling
		Energy		Interests		Total		Energy		Interests		Total
Net income		$	571	$	44	$	615	$	1,052	$	21	$	1,073
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments			114		11		125		(109)		(1)		(110)
Reclassification to net income of foreign currency
translation adjustments related to equity
method investments(2)			―		―		―		(54)		―		(54)
Net actuarial (loss) gain			(5)		―		(5)		8		―		8
Financial instruments			(9)		(13)		(22)		(18)		(34)		(52)
Total other comprehensive income (loss)			100		(2)		98		(173)		(35)		(208)
Total comprehensive income (loss)			671		42		713		879		(14)		865
Preferred dividends of subsidiaries			(5)		―		(5)		(6)		―		(6)
Total comprehensive income (loss), after preferred
dividends of subsidiaries		$	666	$	42	$	708	$	873	$	(14)	$	859
(1)	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
(2)	Related to the acquisition of Chilquinta Energía and Luz del Sur.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30,		December 31,
		2012		2011(1)(2)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	530	$	252
Restricted cash			42		24
Trade accounts receivable, net			922		1,198
Other accounts and notes receivable, net			152		147
Income taxes receivable			18		―
Inventories			398		346
Regulatory balancing accounts — undercollected			301		38
Regulatory assets			88		89
Fixed-price contracts and other derivatives			74		85
U.S. Treasury grants receivable			181		―
Settlements receivable related to wildfire litigation			180		10
Other			192		143
Total current assets			3,078		2,332
Investments and other assets:
Restricted cash			20		22
Regulatory assets arising from pension and other postretirement
benefit obligations			1,027		1,126
Regulatory assets arising from wildfire litigation costs			326		594
Other regulatory assets			1,155		1,060
Nuclear decommissioning trusts			892		804
Investments			1,585		1,671
Goodwill			1,109		1,036
Other intangible assets			441		448
Sundry			767		691
Total investments and other assets			7,322		7,452
Property, plant and equipment:
Property, plant and equipment			33,251		31,192
Less accumulated depreciation and amortization			(8,261)		(7,727)
Property, plant and equipment, net ($473 and $494 at September 30, 2012 and             December 31, 2011, respectively, related to VIE)			24,990		23,465
Total assets		$	35,390	$	33,249
(1)	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
(2)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30,		December 31,
		2012		2011(1)(2)
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt		$	584	$	449
Accounts payable — trade			970		983
Accounts payable — other			126		124
Income taxes payable			―		5
Deferred income taxes			155		173
Dividends and interest payable			309		219
Accrued compensation and benefits			273		323
Regulatory balancing accounts — overcollected			117		105
Current portion of long-term debt			709		336
Fixed-price contracts and other derivatives			82		92
Customer deposits			150		142
Reserve for wildfire litigation			284		586
Other			590		615
Total current liabilities			4,349		4,152
Long-term debt ($337 and $345 at September 30, 2012 and December 31, 2011, respectively,         related to VIE)			11,193		10,078
Deferred credits and other liabilities:
Customer advances for construction			146		142
Pension and other postretirement benefit obligations, net of plan assets			1,337		1,423
Deferred income taxes			1,609		1,520
Deferred investment tax credits			47		49
Regulatory liabilities arising from removal obligations			2,673		2,551
Asset retirement obligations			1,981		1,905
Other regulatory liabilities			55		87
Fixed-price contracts and other derivatives			270		301
Reserve for wildfire litigation			127		10
Deferred credits and other			1,028		774
Total deferred credits and other liabilities			9,273		8,762
Contingently redeemable preferred stock of subsidiary			79		79
Commitments and contingencies (Note 10)
Equity:
Preferred stock (50 million shares authorized; none issued)			―		―
Common stock (750 million shares authorized; 242 million and 240 million shares
outstanding at September 30, 2012 and December 31, 2011, respectively; no par value)			2,178		2,104
Retained earnings			8,293		8,162
Deferred compensation			―		(2)
Accumulated other comprehensive income (loss)			(389)		(489)
Total Sempra Energy shareholders’ equity			10,082		9,775
Preferred stock of subsidiary			20		20
Other noncontrolling interests			394		383
Total equity			10,496		10,178
Total liabilities and equity		$	35,390	$	33,249
(1)	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
(2)	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,
		2012		2011(1)
		(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	615	$	1,073
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization			803		729
Deferred income taxes and investment tax credits			(45)		211
Equity losses (earnings)			346		(41)
Remeasurement of equity method investments			―		(277)
Fixed-price contracts and other derivatives			1		(7)
Other			(8)		(43)
Net change in other working capital components			(373)		(75)
Distributions from RBS Sempra Commodities LLP			―		53
Changes in other assets			202		31
Changes in other liabilities			147		(11)
Net cash provided by operating activities			1,688		1,643
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment			(2,241)		(2,031)
Expenditures for investments and acquisition of businesses, net of cash acquired			(359)		(696)
Proceeds from sale of joint venture interest			9		―
Distributions from RBS Sempra Commodities LLP			―		374
Distributions from other investments			43		47
Purchases of nuclear decommissioning and other trust assets			(534)		(399)
Proceeds from sales by nuclear decommissioning and other trusts			534		398
Decrease in restricted cash			89		473
Increase in restricted cash			(105)		(450)
Other			(12)		(20)
Net cash used in investing activities			(2,576)		(2,304)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid			(405)		(325)
Redemption of subsidiary preferred stock			―		(80)
Preferred dividends paid by subsidiaries			(5)		(6)
Issuances of common stock			50		22
Repurchases of common stock			(16)		(18)
Issuances of debt (maturities greater than 90 days)			2,294		1,525
Payments on debt (maturities greater than 90 days)			(563)		(366)
Decrease in short-term debt, net			(142)		(300)
Purchase of noncontrolling interests			―		(43)
Distributions to noncontrolling interests			(36)		(10)
Other			(20)		5
Net cash provided by financing activities			1,157		404
Effect of exchange rate changes on cash and cash equivalents			9		2
Increase (decrease) in cash and cash equivalents			278		(255)
Cash and cash equivalents, January 1			252		912
Cash and cash equivalents, September 30		$	530	$	657
(1)	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
		Nine months ended September 30,
		2012		2011
		(unaudited)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized		$	278	$	281
Income tax payments, net of refunds			99		106
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Acquisition of businesses:
Assets acquired		$	29	$	2,831
Cash paid, net of cash acquired			(19)		(611)
Fair value of equity method investments immediately prior to the acquisition			―		(882)
Fair value of noncontrolling interests			―		(279)
Additional consideration accrued			―		(32)
Liabilities assumed		$	10	$	1,027
Accrued capital expenditures		$	315	$	306
U.S. Treasury grants receivable(1)			136		―
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
Dividends declared but not paid		$	149	$	119
(1)	Cash grants, excluding $45 million previously recorded in 2011 as investment tax credits.
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
	(unaudited)
Operating revenues
Electric	$	998	$	763	$	2,349	$	2,011
Natural gas		94		105		357		394
Total operating revenues		1,092		868		2,706		2,405
Operating expenses
Cost of electric fuel and purchased power		301		207		604		534
Cost of natural gas		29		40		130		175
Operation and maintenance		309		255		852		756
Depreciation and amortization		128		108		359		316
Franchise fees and other taxes		55		48		144		138
Total operating expenses		822		658		2,089		1,919
Operating income		270		210		617		486
Other income, net		5		26		59		55
Interest expense		(49)		(37)		(124)		(104)
Income before income taxes		226		199		552		437
Income tax expense		(38)		(63)		(151)		(154)
Net income		188		136		401		283
Earnings attributable to noncontrolling interest		(12)		(21)		(23)		(6)
Earnings		176		115		378		277
Preferred dividend requirements		(2)		(2)		(4)		(4)
Earnings attributable to common shares	$	174	$	113	$	374	$	273
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
	Three months ended September 30,
	2012						2011
	(unaudited)
			Non-						Non-
			controlling						controlling
	SDG&E		Interest		Total		SDG&E		Interest		Total
Net income	$	176	$	12	$	188	$	115	$	21	$	136
Other comprehensive income (loss), net of tax:
Net actuarial gain		―		―		―		1		―		1
Financial instruments		―		(4)		(4)		―		(25)		(25)
Total other comprehensive income (loss)		―		(4)		(4)		1		(25)		(24)
Total comprehensive income (loss)	$	176	$	8	$	184	$	116	$	(4)	$	112
	Nine months ended September 30,
	2012						2011
	(unaudited)
			Non-						Non-
			controlling						controlling
	SDG&E		Interest		Total		SDG&E		Interest		Total
Net income	$	378	$	23	$	401	$	277	$	6	$	283
Other comprehensive income (loss), net of tax:
Net actuarial gain		―		―		―		1		―		1
Financial instruments		―		(13)		(13)		―		(34)		(34)
Total other comprehensive income (loss)		―		(13)		(13)		1		(34)		(33)
Total comprehensive income (loss)	$	378	$	10	$	388	$	278	$	(28)	$	250
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30,		December 31,
		2012		2011(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	22	$	29
Restricted cash			11		21
Accounts receivable – trade, net			294		267
Accounts receivable – other, net			20		23
Due from unconsolidated affiliates			17		67
Income taxes receivable			171		102
Inventories			83		82
Regulatory balancing accounts, net			301		38
Regulatory assets arising from fixed-price contracts and other derivatives			63		67
Other regulatory assets			11		11
Fixed-price contracts and other derivatives			25		27
Settlements receivable related to wildfire litigation			180		10
Other			109		51
Total current assets			1,307		795
Other assets:
Restricted cash			20		22
Deferred taxes recoverable in rates			647		570
Regulatory assets arising from fixed-price contracts and other derivatives			138		191
Regulatory assets arising from pension and other postretirement
benefit obligations			287		309
Regulatory assets arising from wildfire litigation costs			326		594
Other regulatory assets			252		160
Nuclear decommissioning trusts			892		804
Sundry			89		70
Total other assets			2,651		2,720
Property, plant and equipment:
Property, plant and equipment			13,827		13,003
Less accumulated depreciation and amortization			(3,196)		(2,963)
Property, plant and equipment, net ($473 and $494 at September 30, 2012 and             December 31, 2011, respectively, related to VIE)			10,631		10,040
Total assets		$	14,589	$	13,555
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30,		December 31,
		2012		2011(1)
		(unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt		$	2	$	―
Accounts payable			304		375
Due to unconsolidated affiliate			20		14
Deferred income taxes			54		62
Dividends and interest payable			55		32
Accrued compensation and benefits			93		124
Current portion of long-term debt			19		19
Fixed-price contracts and other derivatives			54		55
Customer deposits			63		62
Reserve for wildfire litigation			284		586
Other			117		107
Total current liabilities			1,065		1,436
Long-term debt ($337 and $345 at September 30, 2012 and December 31, 2011,     respectively, related to VIE)			4,293		4,058
Deferred credits and other liabilities:
Customer advances for construction			18		20
Pension and other postretirement benefit obligations, net of plan assets			323		342
Deferred income taxes			1,515		1,167
Deferred investment tax credits			26		26
Regulatory liabilities arising from removal obligations			1,575		1,462
Asset retirement obligations			724		693
Fixed-price contracts and other derivatives			220		243
Reserve for wildfire litigation			127		10
Deferred credits and other			421		178
Total deferred credits and other liabilities			4,949		4,141
Contingently redeemable preferred stock			79		79
Commitments and contingencies (Note 10)
Equity:
Common stock (255 million shares authorized; 117 million shares outstanding;
no par value)			1,338		1,338
Retained earnings			2,785		2,411
Accumulated other comprehensive income (loss)			(10)		(10)
Total SDG&E shareholder's equity			4,113		3,739
Noncontrolling interest			90		102
Total equity			4,203		3,841
Total liabilities and equity		$	14,589	$	13,555
(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,
	2012		2011
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	401	$	283
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization		359		316
Deferred income taxes and investment tax credits		262		226
Fixed price contracts and other derivatives		(9)		(13)
Other		(55)		(43)
Net change in other working capital components		(518)		18
Changes in other assets		201		32
Changes in other liabilities		129		―
Net cash provided by operating activities		770		819
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(998)		(1,162)
Purchases of nuclear decommissioning trust assets		(530)		(395)
Proceeds from sales by nuclear decommissioning trusts		524		389
Decrease in restricted cash		74		340
Increase in restricted cash		(62)		(355)
Net cash used in investing activities		(992)		(1,183)
CASH FLOWS FROM FINANCING ACTIVITIES
Capital contribution		―		200
Capital (distribution) contribution at Otay Mesa VIE		(22)		5
Preferred dividends paid		(4)		(4)
Issuance of long-term debt		249		348
Payments on long-term debt		(7)		(7)
Increase in short-term debt, net		2		―
Other		(3)		(2)
Net cash provided by financing activities		215		540
(Decrease) increase in cash and cash equivalents		(7)		176
Cash and cash equivalents, January 1		29		127
Cash and cash equivalents, September 30	$	22	$	303
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	96	$	80
Income tax (refunds) payments, net		(121)		59
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	$	87	$	161
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
Dividends declared but not paid	$	1	$	1
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
	(unaudited)
Operating revenues	$	728	$	844	$	2,328	$	2,776
Operating expenses
Cost of natural gas		175		267		703		1,133
Operation and maintenance		316		331		933		946
Depreciation and amortization		91		83		268		246
Franchise fees and other taxes		27		28		91		94
Total operating expenses		609		709		1,995		2,419
Operating income		119		135		333		357
Other income, net		6		3		14		9
Interest income		―		1		―		1
Interest expense		(17)		(17)		(51)		(52)
Income before income taxes		108		122		296		315
Income tax expense		(37)		(41)		(105)		(106)
Net income		71		81		191		209
Preferred dividend requirements		―		―		(1)		(1)
Earnings attributable to common shares	$	71	$	81	$	190	$	208
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
	Three months ended September 30,
	2012		2011
	(unaudited)
Net income	$	71	$	81
Other comprehensive income, net of tax:
Financial instruments		―		1
Total other comprehensive income		―		1
Total comprehensive income	$	71	$	82
	Nine months ended September 30,
	2012		2011
	(unaudited)
Net income	$	191	$	209
Other comprehensive income, net of tax:
Financial instruments		1		2
Total other comprehensive income		1		2
Total comprehensive income	$	192	$	211
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30,		December 31,
		2012		2011(1)
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	257	$	36
Accounts receivable – trade, net			273		578
Accounts receivable – other, net			72		63
Due from unconsolidated affiliates			280		40
Income taxes receivable			19		17
Inventories			166		151
Regulatory assets			6		9
Other			32		28
Total current assets			1,105		922
Other assets:
Regulatory assets arising from pension and other postretirement
benefit obligations			730		808
Other regulatory assets			117		137
Sundry			11		8
Total other assets			858		953
Property, plant and equipment:
Property, plant and equipment			10,919		10,565
Less accumulated depreciation and amortization			(4,098)		(3,965)
Property, plant and equipment, net			6,821		6,600
Total assets		$	8,784	$	8,475
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30,		December 31,
		2012		2011(1)
		(unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable – trade		$	254	$	315
Accounts payable – other			78		78
Due to unconsolidated affiliate			16		2
Deferred income taxes			42		44
Accrued compensation and benefits			102		99
Regulatory balancing accounts, net			117		105
Current portion of long-term debt			254		257
Customer deposits			76		75
Other			129		172
Total current liabilities			1,068		1,147
Long-term debt			1,409		1,064
Deferred credits and other liabilities:
Customer advances for construction			113		110
Pension and other postretirement benefit obligations, net of plan assets			756		833
Deferred income taxes			652		576
Deferred investment tax credits			21		23
Regulatory liabilities arising from removal obligations			1,084		1,075
Asset retirement obligations			1,197		1,161
Deferred taxes refundable in rates			55		87
Deferred credits and other			195		206
Total deferred credits and other liabilities			4,073		4,071
Commitments and contingencies (Note 10)
Shareholders' equity:
Preferred stock			22		22
Common stock (100 million shares authorized; 91 million shares outstanding;
no par value)			866		866
Retained earnings			1,366		1,326
Accumulated other comprehensive income (loss)			(20)		(21)
Total shareholders' equity			2,234		2,193
Total liabilities and shareholders' equity		$	8,784	$	8,475
(1)	Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Nine months ended September 30,
	2012		2011
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	191	$	209
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization		268		246
Deferred income taxes and investment tax credits		39		79
Other		(9)		(4)
Net change in other working capital components		240		(46)
Changes in other assets		4		17
Changes in other liabilities		13		(6)
Net cash provided by operating activities		746		495
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(462)		(499)
Increase in loans to affiliates, net		(257)		(96)
Net cash used in investing activities		(719)		(595)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuances of long-term debt		348		―
Common dividends paid		(150)		(50)
Payment of long-term debt		―		(250)
Preferred dividends paid		(1)		(1)
Debt issuance costs		(3)		―
Net cash provided by (used in) financing activities		194		(301)
Increase (decrease) in cash and cash equivalents		221		(401)
Cash and cash equivalents, January 1		36		417
Cash and cash equivalents, September 30	$	257	$	16
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	36	$	39
Income tax payments, net of refunds		46		17
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	$	69	$	81
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. GENERAL

PRINCIPLES OF CONSOLIDATION

2012 Business Segment Realignment

Effective January 1, 2012, management realigned some of the company’s major subsidiaries to better fit its strategic direction and to enhance the management and integration of our assets. This realignment resulted in a change in reportable segments in 2012. In accordance with accounting principles generally accepted in the United States (GAAP), historical information for Sempra Energy has been restated in its Condensed Consolidated Financial Statements and these Notes to reflect the effect of this change. All discussions of our operating units and reportable segments in these Notes reflect the new segments and operating structure.

Sempra Energy

Sempra Energy’s Condensed Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 holding company, and its consolidated subsidiaries and variable interest entities (VIEs). Sempra Energy’s principal operating units are

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

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

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

We provide descriptions of each of our segments in Note 11.

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.

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 subsidiaries in Note 4 herein and Note 4 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2011 and in our Current Report on Form 8-K filed on May 11, 2012, discussed below under “Basis of Presentation.”

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 subsidiaries, which comprise less than one percent of its consolidated financial position and results of operations. SoCalGas’ common stock is wholly owned by Pacific Enterprises (PE), 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 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, 2012 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, 2011 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2011 consolidated financial statements. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the interim-period-reporting provisions of GAAP and the Securities and Exchange Commission.

You should read the information in this Quarterly Report in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2011 (the Annual Report) and our Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2012, which are combined reports for Sempra Energy, SDG&E and SoCalGas. You should also read the information in this Quarterly Report in conjunction with Sempra Energy’s Current Report on Form 8-K and accompanying exhibits, filed on May 11, 2012, which updates the information in the Annual Report primarily for the change in reportable segments (discussed above) and change in accounting principle (discussed below) and which we refer to in this Quarterly Report as the Updated Annual Report. Although the Updated Annual Report contains the separate information for SDG&E and SoCalGas, as filed in the Annual Report, the Form 8-K did not provide updates to their information as separate registrants as they were not impacted by the change in reportable segments or change in accounting principle at Sempra Energy.

Sempra South American Utilities has controlling interests in two electric distribution utilities in South America. 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 Mexico, S de RL de CV (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 GAAP provisions governing regulated operations, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report. We follow the same accounting policies for interim reporting purposes, except for the adoption of new accounting standards as we discuss in Note 2.

Change in Accounting Principle

Effective January 1, 2012, we changed our method of accounting for investment tax credits (ITC) from the flow-through method to the deferral method for Sempra Energy. Under the flow-through method, we reduced our income tax expense by the amount of ITC in the year in which the qualifying assets were placed in service. Under the deferral method, we record ITC in the year when the qualifying assets are placed in service as a reduction to the cost of the asset that generated the ITC. This results in lower book depreciation over the life of the asset. This change has no historical or prospective impact on the California Utilities because ITC is effectively deferred as a result of the application of regulatory accounting required under GAAP.

The flow-through method and the deferral method are both acceptable under GAAP, but the deferral method is the preferred method. We believe that the deferral method is preferable for the ITC we receive because it recognizes ITC benefits over the same periods as the associated costs for which the ITC are intended to compensate.

We applied this change in accounting principle by retrospectively adjusting the historical financial statement amounts for all periods presented. Upon adopting the deferral method, we recorded an adjustment for the cumulative effect of the change in accounting principle to reduce Sempra Energy Consolidated retained earnings as of January 1, 2011 by $37 million.

For certain solar and wind generating assets being placed into service during 2011 and 2012, we have elected to seek cash grants rather than ITC for which the projects also qualify. Accordingly, cash grant accounting, which is similar to deferral accounting of ITC, is required to be applied. As a result, the impact of our change in accounting policy for ITC on our financial statements for the three months and nine months ending September 30, 2012 is insignificant. Cash grants are generally expected to be collectable in cash shortly after a project is constructed. Conversion of ITC to cash is generally dependent on reducing cash tax payments.

The following table summarizes the effects of the change in accounting principle on Sempra Energy’s Condensed Consolidated Financial Statements for the historical periods presented.

EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions, except per share amounts)
		Three months ended September 30, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
Income tax expense		$	68	$	7	$	75
Net income			326		(7)		319
Earnings			296		(7)		289
Basic earnings per common share		$	1.23	$	(0.02)	$	1.21
Diluted earnings per common share		$	1.22	$	(0.02)	$	1.20
		Nine months ended September 30, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
Depreciation and amortization		$	730	$	(1)	$	729
Income before income taxes and equity earnings
of certain unconsolidated subsidiaries			1,316		1		1,317
Income tax expense			269		20		289
Net income			1,092		(19)		1,073
Earnings			1,065		(19)		1,046
Basic earnings per common share		$	4.44	$	(0.08)	$	4.36
Diluted earnings per common share		$	4.40	$	(0.08)	$	4.32
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
Net income		$	1,092	$	(19)	$	1,073
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization			730		(1)		729
Deferred income taxes and investment tax credits			224		(13)		211
Net change in other working capital components (income taxes)			(108)		33		(75)
		As of December 31, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED BALANCE SHEET
Property, plant and equipment		$	31,303	$	(111)	$	31,192
Less accumulated depreciation and amortization			(7,731)		4		(7,727)
Property, plant and equipment, net		$	23,572	$	(107)	$	23,465
Income taxes payable		$	16	$	(11)	$	5
Deferred income taxes, noncurrent liability			1,554		(34)		1,520
Deferred credits and other			773		1		774
Retained earnings(1)			8,225		(63)		8,162
(1)	Adjustment includes the cumulative effect of the change in accounting principle of reductions in net income and earnings of $26 million, $30 million, a negligible amount, and $7 million for the years ended December 31, 2011, 2010, 2009 and 2008, respectively.

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) 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRSs)” (ASU 2011-04): ASU 2011-04 amends Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures, and provides changes in the wording used to describe the requirements for measuring fair value and disclosing information about fair value measurement.  ASU 2011-04 results in common fair value measurement and disclosure requirements under both GAAP and IFRSs.

ASU 2011-04 expands fair value measurement disclosures for Level 3 instruments to require

§   quantitative information about the unobservable inputs

§   a description of the valuation process

§   a qualitative discussion about the sensitivity of the measurements

We adopted ASU 2011-04 on January 1, 2012 and it did not affect our financial position, results of operations or cash flows.  The required disclosure is provided in Note 8.

ASU 2011-05, “Presentation of Comprehensive Income” (ASU 2011-05) and ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (ASU 2011-12): ASU 2011-05 amends ASC Topic 220, Comprehensive Income, and eliminates the option to report other comprehensive income and its components in the statement of changes in equity.  The ASU allows an entity an option to present the components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements.

ASU 2011-05 does not change the items that must be reported in other comprehensive income, when an item of other comprehensive income must be reclassified to net income, or the earnings per share computation.

ASU 2011-12 defers the requirement to separately present on the face of the statement of operations or statement of comprehensive income reclassification adjustments for items that are reclassified from other comprehensive income to net income.

We adopted ASU 2011-05 on January 1, 2012 and have elected to present the components of net income and other comprehensive income in two separate, but consecutive, statements for all periods presented.

ASU 2011-11, “Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11): In order to allow for balance sheet comparison between GAAP and IFRSs, ASU 2011-11 requires enhanced disclosures related to financial assets and liabilities eligible for offsetting in the statement of financial position.  An entity will have to disclose both gross and net information about financial instruments and transactions subject to a master netting arrangement and eligible for offset, including cash collateral received and posted.

We will adopt ASU 2011-11 on January 1, 2013 as required and do not expect it to affect our financial position, results of operations or cash flows. We will provide the additional disclosure in our 2013 interim financial statements.

ASU 2012-02, “Testing Indefinite-Lived Intangible Assets for Impairment” (ASU 2012-02): ASU 2012-02 amends ASC Topic 350, Intangibles – Goodwill and Others, to provide an option to first make a qualitative assessment of whether it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount before applying the quantitative impairment test.  An entity is required to perform the quantitative test only if it determines that it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount.

We will adopt ASU 2012-02 for our annual impairment testing as of October 1, 2012 and do not expect it to significantly affect our financial statements.

NOTE 3. ACQUISITION AND INVESTMENT ACTIVITY

We discuss our investments in unconsolidated entities in Note 4.

SEMPRA SOUTH AMERICAN UTILITIES

Chilquinta Energía S.A. (Chilquinta Energía) and Luz del Sur S.A.A. (Luz del Sur)

On April 6, 2011, Sempra South American Utilities acquired from AEI its interests in Chilquinta Energía in Chile and Luz del Sur in Peru, and their subsidiaries. Prior to the acquisition, Sempra South American Utilities and AEI each owned 50 percent of Chilquinta Energía and approximately 38 percent of Luz del Sur and accounted for the investments under the equity method. Upon completion of the acquisition and a public tender offer to the minority shareholders of Luz del Sur, Sempra South American Utilities owned 100 percent of Chilquinta Energía and approximately 80 percent of Luz del Sur, with the remaining shares of Luz del Sur held by institutional investors and the general public. As part of the transaction, Sempra South American Utilities also acquired AEI’s interests in two energy-services companies, Tecnored S.A. (Tecnored) and Tecsur S.A. (Tecsur). We provide additional information about Sempra South American Utilities’ acquisition of Chilquinta Energía and Luz del Sur and the public tender offer in Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Our results for the nine months ended September 30, 2011 include a $277 million gain (both pretax and after-tax) related to the remeasurement of equity method investments, included as Remeasurement of Equity Method Investments on our Condensed Consolidated Statement of Operations.  We discuss the calculation of the gain in Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Our Condensed Consolidated Statements of Operations include 100 percent of the acquired companies’ revenues, net income and earnings of $1.1 billion, $155 million and $135 million, respectively, for the nine months ended September 30, 2012, including revenues, net income, and earnings of $356 million, $56 million and $49 million, respectively, for the three months ended September 30, 2012.  Net income and earnings include holding companies reported in Parent and Other.  Revenues, net income and earnings from the date of acquisition were $706 million, $108 million and $92 million, respectively, for the nine months ended September 30, 2011 and $345 million, $60 million and $52 million, respectively, for the three months ended September 30, 2011. These amounts do not include the remeasurement gain.

Following are pro forma revenues and earnings for Sempra Energy had the acquisition occurred on January 1, 2010, which primarily reflect the changes to revenues and earnings from our increased ownership and consolidation of the entities acquired. Although some short-term debt borrowings may have resulted from the actual acquisition in 2011, we have not assumed any additional interest expense in the pro forma impact on earnings below, as the amounts would be immaterial due to the low interest rates available to us on commercial paper.  The pro forma amounts do not include the impact of the increased ownership in Luz del Sur resulting from the tender offer completed in September 2011 discussed above and in Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

		Three months ended		Nine months ended
(Dollars in millions)		September 30, 2011		September 30, 2011
Revenues		$	2,576	$	7,775
Earnings(1)			289		794	(2)
(1)	As adjusted for the retrospective effect of change in accounting principle as we discuss in Note 1.
(2)	Excludes the $277 million gain related to remeasurement of equity method investments.

SEMPRA NATURAL GAS

Willmut Gas Company

In May 2012, Sempra Natural Gas acquired 100 percent of the outstanding common stock of Willmut Gas Company (Willmut Gas), a regulated natural gas distribution utility serving approximately 20,000 customers in Hattiesburg, Mississippi, in order to expand Sempra Natural Gas’ service area in the Southeast United States.  Willmut Gas was purchased for $19 million in cash and the assumption of $10 million of liabilities.  Included in the acquisition was $17 million in net property, plant and equipment.  As a result of the acquisition, we recorded $10 million of goodwill.

The results of operations for Willmut Gas are included in our Condensed Consolidated Statements of Operations and Cash Flows beginning from the date of acquisition and include revenues of $5 million and negligible earnings for the nine months ended September 30, 2012 and revenues of $3 million and negligible earnings for the three months ended September 30, 2012.

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

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

SEMPRA RENEWABLES

For the nine months ended September 30, 2012, Sempra Renewables invested $296 million in its renewable wind generation joint ventures, of which $249 million was invested in the Flat Ridge 2 Wind Farm project.

SEMPRA NATURAL GAS

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), that links producing areas in the Rocky Mountains region to the upper Midwest and the eastern United States. In August 2012, Kinder Morgan Energy Partners L.P. (KMP) announced the sale of its 50 percent interest in Rockies Express, as part of a larger asset group, to Tallgrass Energy Partners, L.P. (Tallgrass). Phillips 66 owns the remaining interest of 25 percent. Our total investment in Rockies Express is accounted for as an equity method investment.

The general partner of KMP is Kinder Morgan, Inc. (KMI). As a condition of KMI receiving antitrust approval from the Federal Trade Commission (FTC) for its acquisition of El Paso Corporation, KMI agreed to divest certain assets in its natural gas pipeline group.  Included in these assets is KMP’s interest in Rockies Express. KMP recorded remeasurement losses during the first nine months of 2012 associated with these discontinued operations. We have recorded impairments of our partnership investment in Rockies Express of $300 million ($179 million after-tax) in the quarter ended June 30, 2012 and an additional $100 million ($60 million after-tax) in the quarter ended September 30, 2012.  Our remaining carrying value in Rockies Express as of September 30, 2012 is $369 million. We recorded the write-downs as a result of our estimate of fair value for our investment at the reporting date and our conclusion that the impairments are other-than-temporary, as required by GAAP. We discuss the fair value measurement of our investment in Rockies Express in Note 8.

RBS SEMPRA COMMODITIES

RBS Sempra Commodities LLP (RBS Sempra Commodities) is a United Kingdom limited liability partnership that owned and operated commodities-marketing businesses previously owned by us. We and our partner in the joint venture, The Royal Bank of Scotland plc (RBS), sold substantially all of the partnership’s businesses and assets in four separate transactions completed in July, November and December of 2010 and February of 2011. We account for our investment in RBS Sempra Commodities under the equity method, and report our share of partnership earnings and other associated costs in Parent and Other.

In April 2011, we and RBS entered into a letter agreement (Letter Agreement) which amended certain provisions of the agreements that formed RBS Sempra Commodities. The Letter Agreement addresses the wind-down of the partnership and the distribution of the partnership’s remaining assets. In accordance with the Letter Agreement, we received distributions in the nine months ended September 30, 2011 of $329 million on April 15, 2011 and $98 million on August 9, 2011. The investment balance of $126 million at September 30, 2012 reflects remaining distributions expected to be received from the partnership in accordance with the Letter Agreement. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 10 under “Other Litigation.” 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.

In connection with the Letter Agreement described above, we also released RBS from its indemnification obligations with respect to the items for which J.P. Morgan Chase & Co. (JP Morgan), one of the buyers of the partnership’s businesses, has agreed to indemnify us.

We recorded no equity earnings or losses related to the partnership for the three months or nine months ended September 30, 2012.  Pretax equity losses from RBS Sempra Commodities were $16 million and $24 million for the three months and nine months ended September 30, 2011, respectively. Included in the equity losses is an impairment charge of $16 million ($10 million after-tax) for the three months and nine months ended September 30, 2011 to reduce our investment in RBS Sempra Commodities.  We discuss the fair value measurement of our investment in the partnership in Note 8.

We discuss the RBS Sempra Commodities sales transactions, the Letter Agreement and other matters concerning the partnership in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

NOTE 5. OTHER FINANCIAL DATA

U. S. TREASURY GRANTS RECEIVABLE

As of September 30, 2012, Sempra Renewables has recorded grants receivable totaling $181 million. Based on eligible costs at its Mesquite Solar 1 and Copper Mountain Solar 2 generating facilities, the grants are recognized as receivables when the projects, or portions of projects, are placed into service. The grants are expected to be received in 2013.

INVENTORIES

The components of inventories by segment are as follows:

INVENTORY BALANCES
(Dollars in millions)
	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	Natural Gas				Materials and supplies				Total
SDG&E	$	2	$	6	$	81	$	76	$	83	$	82
SoCalGas		142		128		24		23		166		151
Sempra South American Utilities		―		―		37		36		37		36
Sempra Mexico		10		10		8		7		18		17
Sempra Natural Gas		85		51		9		9		94		60
Sempra Energy Consolidated	$	239	$	195	$	159	$	151	$	398	$	346

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 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 impacts on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. SDG&E determines if it is the primary beneficiary in these cases based on 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-megawatt (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 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. SDG&E and Sempra Energy have consolidated Otay Mesa VIE since the second quarter of 2007. Otay Mesa VIE’s equity of $90 million at September 30, 2012 and $102 million at December 31, 2011 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 $347 million at September 30, 2012, 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.

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 as of September 30, 2012. 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. In all other cases, we have determined that these contracts are not variable interests in a VIE and therefore are not subject to the requirements of GAAP concerning the consolidation of VIEs.

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 financial statements of other consolidated VIEs are not material to the financial statements of Sempra Energy. The captions on 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,
	2012		2011		2012		2011
Operating revenues
Electric	$	―	$	―	$	―	$	―
Natural gas		―		―		―		―
Total operating revenues		―		―		―		―
Operating expenses
Cost of electric fuel and purchased power		(26)		(29)		(66)		(55)
Operation and maintenance		4		1		15		23
Depreciation and amortization		7		7		19		20
Total operating expenses		(15)		(21)		(32)		(12)
Operating income		15		21		32		12
Other income (expense), net		―		4		(1)		―
Interest expense		(3)		(4)		(8)		(6)
Income before income taxes/Net income		12		21		23		6
Earnings attributable to noncontrolling interest		(12)		(21)		(23)		(6)
Earnings	$	―	$	―	$	―	$	―

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

GOODWILL

Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized but is tested annually on October 1 for impairment. Impairment of goodwill occurs when the carrying amount (book value) of goodwill exceeds its implied fair value.  If the carrying value of the reporting unit, including goodwill, exceeds its fair value, and the book value of goodwill is greater than its fair value on the test date, we record a goodwill impairment loss.

Goodwill included on the Sempra Energy Condensed Consolidated Balance Sheets is recorded as follows:

GOODWILL
(Dollars in millions)
			Sempra
			South American		Sempra		Sempra
			Utilities		Mexico		Natural Gas		Total
Balance as of December 31, 2011		$	949	$	25	$	62	$	1,036
Foreign currency translation(1)			63		―		―		63
Acquisition of subsidiary			―		―		10		10
Balance at September 30, 2012		$	1,012	$	25	$	72	$	1,109
(1)	We record the offset of this fluctuation to other comprehensive income.

We provide additional information concerning goodwill in Note 3 above and Notes 1 and 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report. 

PENSION AND OTHER POSTRETIREMENT BENEFITS

Remeasurement

The SoCalGas union collective bargaining agreement (CBA) covering wages, hours, working conditions and medical and other benefit plans was ratified on March 1, 2012 and is effective January 1, 2012 through September 30, 2015.  The new CBA includes a change in plans offered for post-65 medical benefits. As a result, SoCalGas changed the option for administering the Medicare Part D benefit to an Employer Group Waiver Plan (EGWP). The EGWP allows a plan sponsor to contract with a Medicare Part D sponsor to receive the benefit of the subsidy through reduced premiums. Because this change in benefits is a significant event under GAAP, SoCalGas was required to remeasure the benefit obligations for this postretirement welfare plan as of February 29, 2012 and determined that a discount rate of 4.65% was appropriate. The effect of the remeasurement was a $66 million decrease in the recorded liability for other postretirement benefits as of March 31, 2012 at SoCalGas and Sempra Energy Consolidated. We discuss the Medicare Part D benefit in Note 8 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Employee Stock Ownership Plan (ESOP)

Sempra Energy terminated the ESOP effective June 30, 2012, as all ESOP debt was paid and all shares were released from the ESOP Trust as of that date. We describe the ESOP and ESOP debt in Note 8 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

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,				Three months ended September 30,
	2012		2011		2012		2011
Service cost	$	23	$	20	$	4	$	8
Interest cost		40		41		11		16
Expected return on assets		(38)		(36)		(13)		(12)
Amortization of:
Prior service cost		―		1		―		―
Actuarial loss		12		8		2		4
Settlement		1		1		―		―
Regulatory adjustment		9		31		3		2
Total net periodic benefit cost	$	47	$	66	$	7	$	18
	Nine months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Service cost	$	68	$	63	$	19	$	23
Interest cost		122		126		39		49
Expected return on assets		(116)		(109)		(40)		(36)
Amortization of:
Prior service cost (credit)		2		3		(2)		―
Actuarial loss		35		26		9		13
Settlement		8		11		―		―
Regulatory adjustment		(9)		6		8		6
Total net periodic benefit cost	$	110	$	126	$	33	$	55

NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended September 30,				Three months ended September 30,
	2012		2011		2012		2011
Service cost	$	7	$	6	$	1	$	1
Interest cost		11		12		2		2
Expected return on assets		(11)		(10)		(1)		(1)
Amortization of:
Prior service cost		―		―		1		1
Actuarial loss		4		2		―		―
Settlement		(1)		―		―		―
Regulatory adjustment		7		15		1		1
Total net periodic benefit cost	$	17	$	25	$	4	$	4
	Nine months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Service cost	$	21	$	21	$	5	$	5
Interest cost		34		37		6		7
Expected return on assets		(35)		(35)		(5)		(5)
Amortization of:
Prior service cost		1		1		3		3
Actuarial loss		11		7		―		―
Settlement		1		1		―		―
Regulatory adjustment		7		13		2		2
Total net periodic benefit cost	$	40	$	45	$	11	$	12

NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended September 30,				Three months ended September 30,
	2012		2011		2012		2011
Service cost	$	13	$	10	$	2	$	7
Interest cost		24		24		9		12
Expected return on assets		(23)		(21)		(10)		(10)
Amortization of:
Prior service cost (credit)		―		1		(1)		(1)
Actuarial loss		6		4		1		4
Regulatory adjustment		2		16		2		1
Total net periodic benefit cost	$	22	$	34	$	3	$	13
	Nine months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Service cost	$	40	$	34	$	12	$	17
Interest cost		74		74		31		39
Expected return on assets		(72)		(64)		(33)		(30)
Amortization of:
Prior service cost (credit)		1		2		(5)		(3)
Actuarial loss		17		12		8		13
Settlement		1		1		―		―
Regulatory adjustment		(16)		(7)		6		4
Total net periodic benefit cost	$	45	$	52	$	19	$	40

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 2012:

	Sempra Energy
(Dollars in millions)	Consolidated		SDG&E		SoCalGas
Contributions through September 30, 2012:
Pension plans	$	111	$	36	$	45
Other postretirement benefit plans		32		10		19
Total expected contributions in 2012:
Pension plans	$	123	$	45	$	47
Other postretirement benefit plans		41		13		23

Expected contributions to our pension plans in 2012 have decreased significantly due to the passage of legislation in July 2012, the Moving Ahead for Progress in the 21st Century Act, that significantly reduces the minimum contributions required for single employer defined benefit plans, but increases premiums to the Pension Benefit Guaranty Corporation.

EARNINGS PER SHARE

The following table provides the per share computations for our earnings for the three months and nine months ended September 30, 2012 and 2011. 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,
		2012		2011(1)		2012		2011(1)
Numerator:
Earnings/Income attributable to common shareholders		$	268	$	289	$	566	$	1,046
Denominator:
Weighted-average common shares
outstanding for basic EPS			241,689		239,545		241,133		239,693
Dilutive effect of stock options, restricted
stock awards and restricted stock units			4,113		2,335		3,880		2,262
Weighted-average common shares
outstanding for diluted EPS			245,802		241,880		245,013		241,955
Earnings per share:
Basic		$	1.11	$	1.21	$	2.35	$	4.36
Diluted		$	1.09	$	1.20	$	2.31	$	4.32
(1)	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

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 and 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 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 during the three months ended September 30, 2012 and 40,000 such antidilutive stock options outstanding during the nine months ended September 30, 2012. We had 2,112,880 and 2,111,839 such stock options outstanding during the three months and nine months ended September 30, 2011, respectively.

We had no stock options outstanding during either the three months or nine months ended September 30, 2012 that were antidilutive because of the unearned compensation and windfall tax benefits included in the assumed proceeds under the treasury stock method.  We had no such stock options during the three months ended September 30, 2011 and 900 such antidilutive stock options during the nine months ended September 30, 2011.

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 and 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 recognized 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 3,387 antidilutive RSUs from the application of unearned compensation in the treasury stock method for the three months and 1,881 such antidilutive RSUs for the nine months ended September 30, 2012. There were 1,109 such antidilutive RSUs for the three months ended September 30, 2011 and no such antidilutive RSUs for the nine months ended September 30, 2011.  There were no such antidilutive RSAs for the three months ended September 30, 2012 and 14,319 such antidilutive RSAs for the nine months ended September 30, 2012. There were no such antidilutive RSAs for the three months and nine months ended September 30, 2011.

Each performance-based RSU represents the right to receive between zero and 1.5 shares of Sempra Energy common stock based on Sempra Energy’s four-year cumulative total shareholder return compared to the Standard & Poor’s (S&P) 500 Utilities Index, as follows:

Four-Year Cumulative Total Shareholder Return Ranking versus S&P 500 Utilities Index(1)	Number of Sempra Energy Common Shares Received for Each Restricted Stock Unit(2)
75th Percentile or Above	1.5
50th Percentile	1
35th Percentile or Below	―
(1) If Sempra Energy ranks at or above the 50th percentile compared to the S&P 500 Index, participants will receive a minimum of 1.0 share for each restricted stock unit.
(2) Participants may also receive additional shares for dividend equivalents on units subject to restricted stock units, which are reinvested to purchase additional units that become subject to the same vesting conditions as the restricted stock units to which the dividends relate.

RSAs have a maximum potential of 100 percent vesting. We include our performance-based RSUs in potential dilutive shares at zero to 150 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 index, dilutive RSU shares may vary widely from period-to-period. We include our RSAs, which are solely service-based, in potential dilutive shares at 100 percent.

RSUs and RSAs may be excluded from potential dilutive shares by the application of unearned compensation in the treasury stock method, as we discuss above, or because performance goals are currently not met.  The maximum excluded RSAs and RSUs, assuming performance goals were met at maximum levels, were 2,349,338 and 2,523,343 for the three months and nine months ended September 30, 2012, respectively, and 3,473,578 and 3,630,253 for the three months and nine months ended September 30, 2011, respectively.

COMMON STOCK REPURCHASE PROGRAM

In September 2010, we entered into a share repurchase program under which we prepaid $500 million to repurchase shares of our common stock in a share forward transaction. The program was completed in March 2011 with a total of 9,574,435 shares repurchased at an average price of $52.22 per share. Our outstanding shares used to calculate earnings per share were reduced by the number of shares repurchased when they were delivered to us, and the $500 million purchase price was recorded as a reduction in shareholders’ equity upon its prepayment. We received 5,670,006 shares during the quarter ended September 30, 2010; 2,407,994 shares on October 4, 2010 and 1,496,435 shares on March 22, 2011.  We discuss the repurchase program further in Note 13 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

PREFERRED STOCK OF SUBSIDIARY

On June 30, 2011, PE redeemed all five series of its outstanding preferred stock for $81 million. Each series was redeemed for cash at redemption prices ranging from $100 to $101.50 per share, plus accrued dividends up to the redemption date of an aggregate of $1 million. The redeemed shares are no longer outstanding and represent only the right to receive the applicable redemption price, to the extent the shares have not yet been presented for payment. We provide more detail concerning PE’s preferred stock in Note 12 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

SHARE-BASED COMPENSATION

We discuss our share-based compensation plans in Note 9 of the Notes to Consolidated Financial Statements in the Updated Annual Report. We recorded share-based compensation expense, net of income taxes, of $5 million and $7 million for the three months ended September 30, 2012 and 2011, respectively, and $18 million and $20 million for the nine months ended September 30, 2012 and 2011, respectively. Pursuant to our share-based compensation plans, we granted 927,734 RSUs and 18,487 RSAs during the nine months ended September 30, 2012, primarily in January.

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.  The following table shows capitalized financing costs for the three months and nine months ended September 30, 2012 and 2011.

CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Sempra Energy Consolidated:
AFUDC related to debt	$	5	$	10	$	32	$	27
AFUDC related to equity		13		26		80		67
Other capitalized financing costs		13		6		40		20
Total Sempra Energy Consolidated	$	31	$	42	$	152	$	114
SDG&E:
AFUDC related to debt	$	3	$	8	$	26	$	22
AFUDC related to equity		6		21		61		54
Total SDG&E	$	9	$	29	$	87	$	76
SoCalGas:
AFUDC related to debt	$	2	$	2	$	6	$	5
AFUDC related to equity		7		5		19		13
Total SoCalGas	$	9	$	7	$	25	$	18

COMPREHENSIVE INCOME

The amounts for comprehensive income in the Condensed Consolidated Statements of Comprehensive Income are net of income tax expense (benefit) as follows:

INCOME TAX EXPENSE (BENEFIT) ASSOCIATED WITH OTHER COMPREHENSIVE INCOME
(Dollars in millions)
		Three months ended September 30,
		2012						2011
		Share-		Non-				Share-		Non-
		holders'		controlling		Total		holders'		controlling		Total
		Equity(1)		Interests		Equity		Equity(1)		Interests		Equity
Sempra Energy Consolidated:
Foreign currency translation adjustments		$	―	$	―	$	―	$	(1)	$	―	$	(1)
Net actuarial (loss) gain			(7)		―		(7)		1		―		1
Financial instruments			(1)		―		(1)		(11)		―		(11)
SoCalGas:
Financial instruments		$	1	$	―	$	1	$	―	$	―	$	―
		Nine months ended September 30,
		2012						2011
		Share-		Non-				Share-		Non-
		holders'		controlling		Total		holders'		controlling		Total
		Equity(1)		Interests		Equity		Equity(1)		Interests		Equity
Sempra Energy Consolidated:
Foreign currency translation adjustments		$	―	$	―	$	―	$	(1)	$	―	$	(1)
Net actuarial (loss) gain			(4)		―		(4)		5		―		5
Financial instruments			(5)		―		(5)		(11)		―		(11)
SoCalGas:
Financial instruments		$	1	$	―	$	1	$	1	$	―	$	1
(1)	Shareholders’ equity of Sempra Energy Consolidated or SoCalGas as indicated in left margin.

Income tax amounts associated with other comprehensive income during the three months and nine months ended September 30, 2012 and 2011 at SDG&E were negligible.

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS

The following two tables provide a reconciliation of Sempra Energy’s and SDG&E’s shareholders’ equity and noncontrolling interests for the nine months ended September 30, 2012 and 2011.

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS
(Dollars in millions)
		Sempra
		Energy		Non-
		Shareholders’		controlling		Total
		Equity		Interests		Equity
Balance at December 31, 2011	$	9,775	$	403	$	10,178
Comprehensive income		671		42		713
Preferred dividends of subsidiaries		(5)		―		(5)
Share-based compensation expense		33		―		33
Common stock dividends declared		(435)		―		(435)
Issuance of common stock		50		―		50
Repurchase of common stock		(16)		―		(16)
Common stock released from ESOP		9		―		9
Equity contributed by noncontrolling interest		―		5		5
Distributions to noncontrolling interests		―		(36)		(36)
Balance at September 30, 2012	$	10,082	$	414	$	10,496
Balance at December 31, 2010	$	8,990	$	211	$	9,201
Comprehensive income (loss)		879		(14)		865
Preferred dividends of subsidiaries		(6)		―		(6)
Share-based compensation expense		36		―		36
Common stock dividends declared		(346)		―		(346)
Issuance of common stock		22		―		22
Tax benefit related to share-based compensation		6		―		6
Repurchase of common stock		(18)		―		(18)
Common stock released from ESOP		15		―		15
Distributions to noncontrolling interests		―		(9)		(9)
Equity contributed by noncontrolling interest		―		6		6
Acquisition of South American entities		―		279		279
Purchase of noncontrolling interests in subsidiary		(4)		(39)		(43)
Redemption of preferred stock of subsidiary		―		(80)		(80)
Balance at September 30, 2011	$	9,574	$	354	$	9,928

SHAREHOLDER’S EQUITY AND NONCONTROLLING INTEREST
(Dollars in millions)
		SDG&E		Non-
		Shareholder’s		controlling		Total
		Equity		Interest		Equity
Balance at December 31, 2011	$	3,739	$	102	$	3,841
Comprehensive income		378		10		388
Preferred stock dividends declared		(4)		―		(4)
Distributions to noncontrolling interest		―		(22)		(22)
Balance at September 30, 2012	$	4,113	$	90	$	4,203
Balance at December 31, 2010	$	3,108	$	113	$	3,221
Comprehensive income (loss)		278		(28)		250
Preferred stock dividends declared		(4)		―		(4)
Capital contribution		200		―		200
Equity contributed by noncontrolling interest		―		6		6
Balance at September 30, 2011	$	3,582	$	91	$	3,673

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.  Net income or loss attributable to the noncontrolling interests is separately identified on the Condensed Consolidated Statements of Operations, and comprehensive income attributable to the noncontrolling interests is separately identified on the Condensed Consolidated Statements of Comprehensive Income.

The preferred stock of SoCalGas is presented at Sempra Energy as a noncontrolling interest at September 30, 2012 and December 31, 2011. The preferred stock of SDG&E is contingently redeemable preferred stock. At Sempra Energy, the preferred stock dividends of both SDG&E and SoCalGas are charges against income related to noncontrolling interests. We provide additional information concerning preferred stock in Note 12 of the Notes to Consolidated Financial Statements in the Updated Annual Report. 

At September 30, 2012 and December 31, 2011, Sempra Energy Consolidated reported the following other noncontrolling ownership interests held by others 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, 2012		December 31, 2011
Bay Gas Storage, Ltd.(1)		9	%	$	19	$	17
Southern Gas Transmission Company(1)		49			1		1
Liberty Gas Storage, LLC(1)		25			13		9
Tecsur		10			4		4
Luz del Sur		20			230		216
Chilquinta Energía subsidiaries		15 - 43			37		34
Otay Mesa VIE (at SDG&E)		100			90		102
Total Sempra Energy				$	394	$	383
(1)	Part of Sempra Natural Gas.

TRANSACTIONS WITH AFFILIATES

Loans to Unconsolidated Affiliates

Sempra South American Utilities has a U.S. dollar-denominated loan to Camuzzi Gas del Sur S.A., an affiliate of the segment’s Argentine investments, which we discuss in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report. At September 30, 2012, the loan has an $18 million principal balance outstanding plus $7 million of accumulated interest at a variable interest rate (7.41 percent as of September 30, 2012). In June 2012, the maturity date of the loan was extended from June 30, 2012 to June 30, 2013. The loan was fully reserved at September 30, 2012 and December 31, 2011.

Investments

Sempra Energy, at Parent and Other, has an investment in bonds issued by Chilquinta Energía that we discuss in Note 5 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Other Affiliate Transactions

Sempra Energy, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Amounts due to/from affiliates are as follows:

AMOUNTS DUE TO AND FROM AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
		September 30,		December 31,
		2012		2011
SDG&E
Current:
Due from SoCalGas		$	16	$	2
Due from various affiliates			1		65
		$	17	$	67
Due to Sempra Energy		$	20	$	14
Income taxes due from Sempra Energy(1)		$	149	$	97
SoCalGas
Current:
Due from Sempra Energy		$	280	$	23
Due from various affiliates			―		17
		$	280	$	40
Due to SDG&E		$	16	$	2
Income taxes due from Sempra Energy(1)		$	15	$	17
(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 the companies’ having always filed a separate return.

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,
	2012		2011		2012		2011
SDG&E	$	2	$	3	$	6	$	6
SoCalGas		17		13		48		38

Transactions with RBS Sempra Commodities

Several of our segments have engaged in transactions with RBS Sempra Commodities. As a result of the divestiture of substantially all of RBS Sempra Commodities’ businesses, transactions between our segments and RBS Sempra Commodities were assigned over time to the buyers of the joint venture businesses. The assignments of the related contracts were substantially completed by May 1, 2011. Amounts in our Condensed Consolidated Statements of Operations related to these transactions are as follows:

AMOUNTS RECORDED FOR TRANSACTIONS WITH RBS SEMPRA COMMODITIES
(Dollars in millions)
		Three months ended September 30, 2011(1)		Nine months ended September 30, 2011(1)
Revenues:
Sempra Mexico		$	―	$	37
Sempra Natural Gas			―		7
Cost of natural gas:
Sempra Mexico		$	3	$	74
Sempra Natural Gas			―		3
(1)	With the exception of Sempra Mexico, whose contract with RBS Sempra Commodities expired in July 2011, amounts only include activities prior to May 1, 2011, the date by which substantially all the contracts with RBS Sempra Commodities were assigned to buyers of the joint venture businesses.

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,
		2012		2011		2012		2011
Sempra Energy Consolidated:
Allowance for equity funds used during construction		$	13	$	26	$	80	$	67
Investment gains (losses)(1)			17		(6)		27		13
Gains (losses) on interest rate and foreign exchange instruments, net			1		(26)		11		(14)
Regulatory interest, net(2)			―		―		1		1
Sundry, net			13		18		18		19
Total		$	44	$	12	$	137	$	86
SDG&E:
Allowance for equity funds used during construction		$	6	$	21	$	61	$	54
Regulatory interest, net(2)			―		―		1		1
Sundry, net			(1)		5		(3)		―
Total		$	5	$	26	$	59	$	55
SoCalGas:
Allowance for equity funds used during construction		$	7	$	5	$	19	$	13
Sundry, net			(1)		(2)		(5)		(4)
Total		$	6	$	3	$	14	$	9
(1)	Represents investment gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
(2)	Interest on regulatory balancing accounts.

INCOME TAXES

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
		Three months ended September 30,
	2012					2011
			Effective				Effective
		Income Tax	Income			Income Tax	Income
		Expense	Tax Rate			Expense	Tax Rate
Sempra Energy Consolidated	$	49	15	%	$	75	19	%
SDG&E		38	17			63	32
SoCalGas		37	34			41	34
		Nine months ended September 30,
	2012					2011
			Effective				Effective
		Income Tax	Income			Income Tax	Income
		Expense	Tax Rate			Expense	Tax Rate
Sempra Energy Consolidated	$	48	8	%	$	289	22	%
SDG&E		151	27			154	35
SoCalGas		105	35			106	34

Changes in Effective Income Tax Rates

Sempra Energy Consolidated

The lower effective income tax rate in the three months ended September 30, 2012 was primarily due to:

§   $38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012. The change in income tax treatment was made pursuant to an Internal Revenue Service Revenue Procedure allowing certain capitalized repair costs for electric transmission and distribution assets to be deducted from taxable income when incurred for tax years beginning on or after January 1, 2011; and

§   higher planned renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; offset by

§   higher income tax expense in 2012 due to Mexican currency translation and inflation adjustments; and

§   higher income tax expense due to unfavorable resolution of prior years’ income tax items.

The lower effective income tax rate in the nine months ended September 30, 2012 was primarily due to:

§   $54 million income tax benefit primarily associated with our decision to hold life insurance contracts kept in support of certain benefit plans to term. Previously, we took the position that we might cash in or sell these contracts before maturity, which required that we record deferred income taxes on unrealized gains on investments held within the insurance contracts;

§   $38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012, as discussed above; and

§   higher planned renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; offset by

§   lower income in 2012 in countries with lower statutory income tax rates; such income was higher in 2011 due to the $277 million non-taxable gain from our equity method investments related to our acquisition from AEI of its investments in Chile and Peru;

§   higher income tax expense in 2012 due to Mexican currency translation and inflation adjustments;

§   higher income tax expense due to unfavorable resolution of prior years’ income tax items; and

§   higher U.S. income tax on non-U.S. non-operating activity due to the expiration of the look-through rule, as we discuss below.

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 spread evenly over the year. The forecasted items, anticipated on a full year basis, may include, among others, self-developed software, repairs to certain utility plant fixed 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, and depreciation on a certain portion of utility plant assets. Items that cannot be reliably forecasted (e.g., adjustments related to prior years’ income tax items, Mexican currency translation and inflation adjustments, deferred income tax benefit associated with the impairment of a book investment, etc.) are recorded in the interim period in which they actually occur, which can result in variability to income tax expense.

We have used grant accounting for certain assets placed into service in 2012, including assets that were under construction in 2011, in anticipation of applying for cash grants. Grant accounting for cash grants is very similar to the deferral method of accounting for investment tax credits, the primary difference being the recording of a grant receivable instead of an income tax receivable.

Under the deferral method of accounting for ITC and under grant accounting for cash grants, a deferred income tax benefit, on day one, is reflected in income tax expense by recording a deferred tax asset when renewable energy assets are placed in service. This deferred tax asset results from the day-one difference in the income tax basis and financial statement basis of the renewable energy assets, referred to as the “day-one basis difference.” The financial statement basis of the assets is reduced by 100 percent of the ITC or grant expected; U.S. federal income tax basis is reduced by only 50 percent for both ITC and grants; and state income tax basis is reduced 50 percent for grants and not at all for ITC.

In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Act) was signed into law. The 2010 Tax Act extended for years 2010 and 2011 the U.S. federal income tax law known as the look-through rule. This rule allows, under certain situations, for certain non-operating activity (e.g., dividend income, royalty income, interest income, rental income, etc.), of a greater than 50-percent owned non-U.S. subsidiary, to not be taxed under U.S. federal income tax law. As of September 30, 2012, this rule has not yet been extended beyond 2011, which has a negative impact on Sempra Energy’s effective income tax rate for 2012.

SDG&E

The decrease in the effective income tax rate in the three months ended September 30, 2012 was primarily due to:

§   $38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012.  The change in income tax treatment was made pursuant to an Internal Revenue Service Revenue Procedure allowing certain capitalized repair costs for electric transmission and distribution assets to be deducted from taxable income when incurred for tax years beginning on or after January 1, 2011; and

§   higher favorable resolutions of prior years' income tax items; offset by

§   the impact of Otay Mesa VIE, as we discuss below; and

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

The decrease in the effective tax rate in the nine months ended September 30, 2012 was primarily due to:

§   $38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012, as discussed above;

§   the impact of Otay Mesa VIE, as we discuss below;

§   lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and

§   higher favorable resolutions of prior years’ income tax items; offset by

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

Results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is consolidated, and therefore, their effective income tax rates are impacted by the VIE’s stand-alone effective income tax rate.

SoCalGas

While the effective income tax rate for the three months ended September 30, 2012 did not change significantly from the same period in 2011, it was impacted by:

§   lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and

§   higher exclusions from taxable income of the equity portion of AFUDC; offset by

§   lower deductions for cost of removal of utility plant fixed assets.

The increase in the effective income tax rate in the nine months ended September 30, 2012 was primarily due to:

§   lower deductions for self-developed software costs; offset by

§   lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and

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

The California Public Utilities Commission (CPUC) requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income taxes are not recorded to deferred income tax expense, but rather to a regulatory asset or liability. 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 to a certain portion of utility plant fixed assets

§   the equity portion of AFUDC

§   cost of removal of utility plant assets

§   self-developed software costs

§   depreciation on a certain portion of utility plant fixed assets

NOTE 6. DEBT AND CREDIT FACILITIES

COMMITTED LINES OF CREDIT

At September 30, 2012, Sempra Energy Consolidated had an aggregate of $4.1 billion in committed lines of credit to provide liquidity and to support commercial paper and variable-rate demand notes, the major components of which we detail below. Available unused credit on these lines at September 30, 2012 was $3.5 billion.

Sempra Energy

In March 2012, Sempra Energy entered into a new $1.067 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. serves as administrative agent for the syndicate of 24 lenders. No single lender has greater than a 7-percent share. The new facility replaced the $1.0 billion credit agreement that was scheduled to expire in 2014.

Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and 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 $700 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, 2012, Sempra Energy had $47 million of letters of credit outstanding supported by the facility.

Sempra Global

In March 2012, Sempra Global entered into a $2.189 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. serves as administrative agent for the syndicate of 25 lenders. No single lender has greater than a 7-percent share. The new facility replaced the $2.0 billion credit agreement that was scheduled to expire in 2014.

Sempra Energy guarantees Sempra Global’s obligations under the credit facility. Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter.

At September 30, 2012, Sempra Global had $545 million of commercial paper outstanding supported by the facility. At December 31, 2011, $400 million of commercial paper outstanding was classified as long-term debt based on management’s intent and ability to maintain this level of borrowing on a long-term basis either supported by this credit facility or by issuing long-term debt. This classification has no impact on cash flows. As a result of issuances of long-term debt in the nine months ended September 30, 2012, as we discuss below, none of the commercial paper outstanding at September 30, 2012 is classified as long-term debt.

California Utilities

In March 2012, SDG&E and SoCalGas entered into a new combined $877 million, five-year syndicated revolving credit agreement expiring in March 2017. JPMorgan Chase Bank, N.A. serves as administrative agent for the syndicate of 24 lenders. No single lender has greater than a 7-percent share. The agreement permits each utility to individually borrow up to $658 million, subject to a combined limit of $877 million 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 $200 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. The new facility replaced the $800 million combined credit agreement that was scheduled to expire in 2014.

Borrowings under the facility bear interest at benchmark rates plus a margin that varies with market index rates and the borrowing utility’s credit ratings. 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.

At September 30, 2012, SoCalGas had no outstanding borrowings and SDG&E had $2 million of commercial paper outstanding supported by the facility. Available unused credit on the line at September 30, 2012 was $656 million at SDG&E and $658 million at SoCalGas, subject to the combined limit on the facility of $877 million.

GUARANTEES

RBS Sempra Commodities

As we discuss in Note 4, in 2010 and early 2011, Sempra Energy, RBS and RBS Sempra Commodities sold substantially all of the businesses and assets within the partnership in four separate transactions. In connection with each of these transactions, the buyers were, subject to certain qualifications, obligated to replace any guarantees that we had issued in connection with the applicable businesses sold with guarantees of their own. The buyers have substantially completed this process with regard to all existing, open positions, except for one remaining position expected to terminate by January 2013. For those guarantees which have not been replaced, the buyers are obligated to indemnify us in accordance with the applicable transaction documents for any claims or losses in connection with the guarantees that we issued associated with the businesses sold.

At September 30, 2012, RBS Sempra Commodities no longer requires significant working capital support. However, we have provided back-up guarantees for a portion of RBS Sempra Commodities’ remaining trading obligations. A few of these back-up guarantees may continue for a prolonged period of time. RBS has fully indemnified us for any claims or losses in connection with these arrangements, with the exception of those obligations for which JP Morgan has agreed to indemnify us. We discuss the indemnification release in Note 4. We discuss additional matters related to our investment in RBS Sempra Commodities in Note 10.

WEIGHTED AVERAGE INTEREST RATES

The weighted average interest rates on the total short-term debt outstanding at Sempra Energy were 0.82 percent and 0.93 percent at September 30, 2012 and December 31, 2011, respectively. The weighted average interest rate on the total short-term debt outstanding at SDG&E was 0.2 percent at September 30, 2012.  The weighted average interest rates at Sempra Energy at December 31, 2011 include interest rates for commercial paper borrowings classified as long-term, as we discuss above.

LONG-TERM DEBT

Sempra Energy

In March 2012, Sempra Energy publicly offered and sold $600 million of 2.30-percent notes maturing in 2017. In September 2012, Sempra Energy publicly offered and sold $500 million of 2.875-percent notes maturing in 2022.

SDG&E

In March 2012, SDG&E publicly offered and sold $250 million of 4.30-percent first mortgage bonds maturing in 2042.

In September 2012, SDG&E remarketed $161 million of variable rate demand notes at a fixed rate of 1.65 percent maturing in 2018 and $75 million of variable rate demand notes at a fixed rate of 4.00 percent maturing in 2039.

SoCalGas

In September 2012, SoCalGas publicly offered and sold $350 million of 3.75-percent first mortgage bonds maturing in 2042.

Sempra South American Utilities

In February 2012, Luz del Sur publicly offered and sold Peruvian corporate bonds, denominated in the local currency, in the amounts of $21 million at 5.97 percent maturing in 2017 and $9 million at 6.34 percent maturing in 2019. In July 2012, Luz del Sur publicly offered and sold $25 million of Peruvian corporate bonds, denominated in the local currency, at 5.44 percent and maturing in 2019.

Sempra Renewables

In June 2012, Sempra Renewables obtained a $117 million loan, the proceeds of which were applied to construction costs of the Copper Mountain Solar 1 project. The loan fully matures in December 2028. To partially moderate its exposure to interest rate changes, Sempra Renewables has also entered into floating-to-fixed interest rate swaps maturing December 2028. Accordingly, $88 million of this loan has interest rates that are effectively fixed at 4.54 percent. The remaining balance bears interest at rates varying with market rates (2.86 percent at September 30, 2012).

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 (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 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 instruments 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.

§   The California Utilities use natural gas energy derivatives, on their customers’ behalf, with the objective of managing price risk and basis risks, and lowering natural gas costs. These derivatives include fixed price natural gas positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas 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 as of September 30, 2012 and December 31, 2011 as follows:

Segment and Commodity		September 30, 2012	December 31, 2011
California Utilities:
SDG&E:
Natural gas		23 million MMBtu	35 million MMBtu	(1)
Congestion revenue rights		18 million MWh	19 million MWh	(2)
Energy-Related Businesses:
Sempra Natural Gas:
Electric power		2 million MWh	5 million MWh
Natural gas		32 million MMBtu	20 million MMBtu
Sempra Mexico - natural gas		1 million MMBtu	1 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 our customers, assets and other contractual obligations, 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, which are 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. 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 natural gas derivatives. Accordingly, interest rate derivatives are generally accounted for as hedges at the California Utilities, as well as at the rest of Sempra Energy’s subsidiaries. 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.

The net notional amounts of our interest rate derivatives as of September 30, 2012 and December 31, 2011 were:

		September 30, 2012			December 31, 2011
(Dollars in millions)		Notional Debt		Maturities	Notional Debt		Maturities
Sempra Energy Consolidated(1)		$	6-369	2013-2028	$	15-305	2013-2019
SDG&E(1)			285-347	2019		285-355	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 primarily as a result of our Mexican subsidiaries, which have U.S. dollar denominated 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 short-term 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.

FINANCIAL STATEMENT PRESENTATION

The following tables provide the fair values of derivative instruments, without consideration of margin deposits held or posted, on the Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011:

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30, 2012
									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 designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Interest rate instruments(3)		$	6	$	15	$	(20)	$	(69)
Commodity contracts not subject to rate recovery			―		―		(3)		―
Total		$	6	$	15	$	(23)	$	(69)
SDG&E:
Interest rate instruments(3)		$	―	$	―	$	(17)	$	(68)
Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments		$	8	$	43	$	(8)	$	(38)
Commodity contracts not subject to rate recovery			119		19		(131)		(31)
Associated offsetting commodity contracts			(111)		(15)		111		15
Commodity contracts subject to rate recovery			9		20		(39)		(7)
Associated offsetting commodity contracts			(5)		(1)		5		1
Total		$	20	$	66	$	(62)	$	(60)
SDG&E:
Commodity contracts subject to rate recovery		$	7	$	20	$	(37)	$	(7)
Associated offsetting commodity contracts			(4)		(1)		4		1
Total		$	3	$	19	$	(33)	$	(6)
SoCalGas:
Commodity contracts subject to rate recovery		$	2	$	―	$	(2)	$	―
Associated offsetting commodity contracts			(1)		―		1		―
Total		$	1	$	―	$	(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.

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		December 31, 2011
									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 designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Interest rate instruments(3)		$	5	$	11	$	(17)	$	(65)
SDG&E:
Interest rate instruments(3)		$	―	$	―	$	(16)	$	(65)
Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
Interest rate instruments		$	8	$	41	$	(7)	$	(36)
Commodity contracts not subject to rate recovery			156		72		(148)		(94)
Associated offsetting commodity contracts			(120)		(68)		120		68
Commodity contracts subject to rate recovery			28		8		(62)		(24)
Associated offsetting commodity contracts			(10)		(2)		10		2
Total		$	62	$	51	$	(87)	$	(84)
SDG&E:
Commodity contracts subject to rate recovery		$	22	$	8	$	(55)	$	(24)
Associated offsetting commodity contracts			(5)		(2)		5		2
Total		$	17	$	6	$	(50)	$	(22)
SoCalGas:
Commodity contracts subject to rate recovery		$	6	$	―	$	(7)	$	―
Associated offsetting commodity contracts			(5)		―		5		―
Total		$	1	$	―	$	(2)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

The effects of derivative instruments designated as hedges on the Condensed Consolidated Statements of Operations and on Other Comprehensive Income (OCI) and Accumulated Other Comprehensive Income (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)
			Gain on derivatives recognized in earnings				Gain (loss) on derivatives recognized in earnings
			Three months ended September 30,				Nine months ended September 30,
		Location	2012		2011		2012		2011
Sempra Energy Consolidated:
Interest rate instruments		Interest Expense	$	1	$	2	$	5	$	7
Interest rate instruments		Other Income, Net		4		13		6		16
Total(1)			$	5	$	15	$	11	$	23
SoCalGas:
Interest rate instrument		Interest Expense	$	―	$	―	$	―	$	1
Interest rate instrument		Other Income, Net		―		―		―		(3)
Total(1)			$	―	$	―	$	―	$	(2)
(1)	There has been no hedge ineffectiveness on these swaps. Changes in the fair values of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt.

CASH FLOW HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
		Pretax loss recognized					Gain (loss) reclassified from AOCI
		in OCI (effective portion)					into earnings (effective portion)
		Three months ended September 30,					Three months ended September 30,
		2012		2011		Location	2012		2011
Sempra Energy Consolidated:
Interest rate instruments(1)		$	(6)	$	(21)	Interest Expense	$	(3)	$	4
						Equity Losses,
Interest rate instruments			(6)		(27)	Before Income Tax		(4)		(2)
Commodity contracts not subject						Cost of Natural Gas, Electric
to rate recovery			(3)		―	Fuel and Purchased Power		―		―
Total		$	(15)	$	(48)		$	(7)	$	2
SDG&E:
Interest rate instruments(1)		$	(6)	$	(21)	Interest Expense	$	(2)	$	4
SoCalGas:
Interest rate instruments		$	―	$	―	Interest Expense	$	(1)	$	(1)
		Nine months ended September 30,					Nine months ended September 30,
		2012		2011		Location	2012		2011
Sempra Energy Consolidated:
Interest rate instruments(1)		$	(21)	$	(32)	Interest Expense	$	(5)	$	―
						Equity Losses,
Interest rate instruments			(12)		(34)	Before Income Tax		(4)		(3)
Commodity contracts not subject						Cost of Natural Gas, Electric
to rate recovery			(3)		―	Fuel and Purchased Power		―		―
Total		$	(36)	$	(66)		$	(9)	$	(3)
SDG&E:
Interest rate instruments(1)		$	(16)	$	(32)	Interest Expense	$	(3)	$	2
SoCalGas:
Interest rate instruments		$	―	$	―	Interest Expense	$	(2)	$	(3)
(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. There has been a negligible amount of ineffectiveness related to these swaps.

Sempra Energy expects that losses of $18 million, which are net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts that are currently outstanding mature.

SDG&E and SoCalGas expect that losses of $8 million and $1 million, respectively, which are net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings.

For all forecasted transactions, the maximum term over which we are hedging exposure to the variability of cash flows at September 30, 2012 is approximately 17 years and 7 years for Sempra Energy and SDG&E, respectively. The maximum term of hedged interest rate variability related to debt at Sempra Renewables’ equity method investees is 18 years.

We recorded $1 million of hedge ineffectiveness in both the three months and nine months ended September 30, 2012.

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)
		Gain (loss) on derivatives recognized in earnings
		Three months ended September 30,				Nine months ended September 30,
	Location	2012		2011		2012		2011
Sempra Energy Consolidated:
Interest rate and foreign exchange
instruments	Other Income, Net	$	1	$	(26)	$	11	$	(14)
Commodity contracts not subject	Revenues: Energy-Related
to rate recovery	Businesses		(5)		3		(3)		17
Commodity contracts not subject	Cost of Natural Gas, Electric
to rate recovery	Fuel and Purchased Power		―		―		―		1
Commodity contracts not subject
to rate recovery	Operation and Maintenance		1		―		1		1
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power		41		(15)		32		(6)
Commodity contracts subject
to rate recovery	Cost of Natural Gas		―		(2)		(1)		(1)
Total		$	38	$	(40)	$	40	$	(2)
SDG&E:
Commodity contracts not subject
to rate recovery	Operation and Maintenance	$	―	$	(1)	$	―	$	―
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power		41		(15)		32		(6)
Total		$	41	$	(16)	$	32	$	(6)
SoCalGas:
Commodity contracts not subject
to rate recovery	Operation and Maintenance	$	1	$	(1)	$	1	$	―
Commodity contracts subject
to rate recovery	Cost of Natural Gas		―		(2)		(1)		(1)
Total		$	1	$	(3)	$	―	$	(1)

CONTINGENT FEATURES

For Sempra Energy and SDG&E, certain of our derivative instruments contain credit limits which vary depending upon 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 and SDG&E, the total fair value of this group of derivative instruments in a net liability position at September 30, 2012 is $11 million and $6 million, respectively. As of September 30, 2012, if the credit ratings of Sempra Energy and SDG&E were reduced below investment grade, $11 million and $6 million, respectively, of additional assets could be required to be posted as collateral for these derivative contracts.

For Sempra Energy, 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 Notes 1 and 2 of the Notes to Consolidated Financial Statements in the Updated Annual Report. We have not changed the valuation techniques or inputs we use to measure fair value during the nine months ended September 30, 2012.

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 as of September 30, 2012 and December 31, 2011. 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 determined in accordance with our netting policy, as discussed below under “Derivative Positions Net of Cash Collateral.”

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 as of September 30, 2012 and December 31, 2011 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 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). All Level 3 recurring items are related to CRRs at SDG&E, as discussed below under “Level 3 Information.” Commodity derivative contracts that are subject to rate recovery are recorded 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.

RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		At fair value as of September 30, 2012
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	529	$	―	$	―	$	―	$	529
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			72		74		―		―		146
Municipal bonds			―		66		―		―		66
Other securities			―		123		―		―		123
Total debt securities			72		263		―		―		335
Total nuclear decommissioning trusts(1)			601		263		―		―		864
Interest rate instruments			―		73		―		―		73
Commodity contracts subject to rate recovery			21		―		23		―		44
Commodity contracts not subject to rate recovery			19		19		―		―		38
Investments			1		―		―		―		1
Total		$	642	$	355	$	23	$	―	$	1,020
Liabilities:
Interest rate and foreign exchange instruments		$	―	$	136	$	―	$	―	$	136
Commodity contracts subject to rate recovery			32		8		―		(32)		8
Commodity contracts not subject to rate recovery			9		30		―		(13)		26
Total		$	41	$	174	$	―	$	(45)	$	170
		At fair value as of December 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	468	$	―	$	―	$	―	$	468
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			92		78		―		―		170
Municipal bonds			―		77		―		―		77
Other securities			―		78		―		―		78
Total debt securities			92		233		―		―		325
Total nuclear decommissioning trusts(1)			560		233		―		―		793
Interest rate instruments			―		66		―		―		66
Commodity contracts subject to rate recovery			10		1		23		―		34
Commodity contracts not subject to rate recovery			15		35		―		(2)		48
Investments			5		―		―		―		5
Total		$	590	$	335	$	23	$	(2)	$	946
Liabilities:
Interest rate instruments		$	1	$	124	$	―	$	―	$	125
Commodity contracts subject to rate recovery			61		13		―		(61)		13
Commodity contracts not subject to rate recovery			1		52		―		(4)		49
Total		$	63	$	189	$	―	$	(65)	$	187
(1)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
		At fair value as of September 30, 2012
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	529	$	―	$	―	$	―	$	529
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			72		74		―		―		146
Municipal bonds			―		66		―		―		66
Other securities			―		123		―		―		123
Total debt securities			72		263		―		―		335
Total nuclear decommissioning trusts(1)			601		263		―		―		864
Commodity contracts subject to rate recovery			19		―		23		―		42
Commodity contracts not subject to rate recovery			2		―		―		―		2
Total		$	622	$	263	$	23	$	―	$	908
Liabilities:
Interest rate instruments		$	―	$	85	$	―	$	―	$	85
Commodity contracts subject to rate recovery			32		7		―		(32)		7
Total		$	32	$	92	$	―	$	(32)	$	92
		At fair value as of December 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	468	$	―	$	―	$	―	$	468
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			92		78		―		―		170
Municipal bonds			―		77		―		―		77
Other securities			―		78		―		―		78
Total debt securities			92		233		―		―		325
Total nuclear decommissioning trusts(1)			560		233		―		―		793
Commodity contracts subject to rate recovery			9		―		23		―		32
Commodity contracts not subject to rate recovery			1		―		―		―		1
Total		$	570	$	233	$	23	$	―	$	826
Liabilities:
Interest rate instruments		$	―	$	81	$	―	$	―	$	81
Commodity contracts subject to rate recovery			61		12		―		(61)		12
Total		$	61	$	93	$	―	$	(61)	$	93
(1)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
	At fair value as of September 30, 2012
								Collateral
		Level 1		Level 2		Level 3		netted		Total
Assets:
Commodity contracts subject to rate recovery	$	2	$	―	$	―	$	―	$	2
Commodity contracts not subject to rate recovery		2		―		―		―		2
Total	$	4	$	―	$	―	$	―	$	4
Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
Total	$	―	$	1	$	―	$	―	$	1
	At fair value as of December 31, 2011
								Collateral
		Level 1		Level 2		Level 3		netted		Total
Assets:
Commodity contracts subject to rate recovery	$	1	$	1	$	―	$	―	$	2
Commodity contracts not subject to rate recovery		2		―		―		―		2
Total	$	3	$	1	$	―	$	―	$	4
Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
Total	$	―	$	1	$	―	$	―	$	1

Level 3 Information

The following table sets forth reconciliations of changes in the fair value of CRRs classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E:

	Three months ended September 30,
(Dollars in millions)	2012		2011
Balance as of July 1	$	13	$	3
Realized and unrealized gains		16		5
Allocated transmission instruments		17		―
Settlements		(23)		(5)
Balance as of September 30	$	23	$	3
Change in unrealized gains or losses relating to
instruments still held at September 30	$	―	$	―

	Nine months ended September 30,
(Dollars in millions)	2012		2011
Balance as of January 1	$	23	$	2
Realized and unrealized gains		23		17
Allocated transmission instruments		18		2
Settlements		(41)		(18)
Balance as of September 30	$	23	$	3
Change in unrealized gains or losses relating to
instruments still held at September 30	$	―	$	―

CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California Independent System Operator (ISO), an objective source. The impact associated with discounting is negligible. Because auction prices are a less observable input, these instruments are classified as Level 3. Auction prices range from $(3) per MWh to $5 per MWh at a given location, and 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. The earnings impacts of CRRs are deferred and recorded in regulatory accounts to the extent they are recoverable or refundable through rates. Upon settlement, CRRs are included in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations.

Derivative Positions Net of Cash Collateral

Each Condensed Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when management believes a legal right of offset exists.

The following table provides the amount of fair value of cash collateral receivables that were not offset in the Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011:

	September 30,		December 31,
(Dollars in millions)	2012		2011
Sempra Energy Consolidated	$	46	$	20
SDG&E		20		10
SoCalGas		4		2

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. The following table provides the carrying amounts and fair values of certain other financial instruments at September 30, 2012 and December 31, 2011:

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
		September 30, 2012
		Carrying		Fair Value
		Amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Investments in affordable housing partnerships(1)		$	16	$	―	$	―	$	46	$	46
Total long-term debt(2)			11,727		―		12,556		755		13,311
Preferred stock of subsidiaries			99		―		108		―		108
SDG&E:
Total long-term debt(3)		$	4,137	$	―	$	4,308	$	347	$	4,655
Contingently redeemable preferred stock			79		―		86		―		86
SoCalGas:
Total long-term debt(4)		$	1,662	$	―	$	1,872	$	―	$	1,872
Preferred stock			22		―		24		―		24
		December 31, 2011
		Carrying		Fair Value
		Amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Investments in affordable housing partnerships(1)		$	21	$	―	$	―	$	48	$	48
Total long-term debt(2)			9,826		―		10,447		600		11,047
Preferred stock of subsidiaries			99		―		106		―		106
SDG&E:
Total long-term debt(3)		$	3,895	$	―	$	3,933	$	355	$	4,288
Contingently redeemable preferred stock			79		―		86		―		86
SoCalGas:
Total long-term debt(4)		$	1,313	$	―	$	1,506	$	―	$	1,506
Preferred stock			22		―		23		―		23
(1)	We discuss our investments in affordable housing partnerships in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
(2)	Before reductions for unamortized discount (net of premium) of $17 million at September 30, 2012 and $16 million at December 31, 2011, and excluding capital leases of $192 million at September 30, 2012 and $204 million at December 31, 2011, and commercial paper classified as long-term debt of $400 million at December 31, 2011. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
(3)	Before reductions for unamortized discount of $12 million at September 30, 2012 and $11 million at December 31, 2011, and excluding capital leases of $187 million at September 30, 2012 and $193 million at December 31, 2011.
(4)	Before reductions for unamortized discount of $4 million at September 30, 2012 and $3 million at December 31, 2011, and excluding capital leases of $5 million at September 30, 2012 and $11 million at December 31, 2011.

We calculate the fair value of our investments in affordable housing partnerships using an income approach based on the present value of estimated future cash flows discounted at rates available for similar investments (Level 3).

We base the fair value of certain of our 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).

Nuclear Decommissioning Trusts

We discuss SDG&E’s investments in nuclear decommissioning trust funds in Note 6 of the Notes to Consolidated Financial Statements in the Updated Annual Report. The following table shows the fair values and gross unrealized gains and losses for the securities held in the trust funds:

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
			Cost		Gains		Losses		Value
As of September 30, 2012:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies(1)		$	134	$	12	$	―	$	146
Municipal bonds(2)			60		6		―		66
Other securities(3)			114		9		―		123
Total debt securities			308		27		―		335
Equity securities			249		284		(4)		529
Cash and cash equivalents			28		―		―		28
Total		$	585	$	311	$	(4)	$	892
As of December 31, 2011:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		$	157	$	13	$	―	$	170
Municipal bonds			72		5		―		77
Other securities			76		3		(1)		78
Total debt securities			305		21		(1)		325
Equity securities			246		227		(5)		468
Cash and cash equivalents			11		―		―		11
Total		$	562	$	248	$	(6)	$	804
(1)	Maturity dates are 2013-2042
(2)	Maturity dates are 2012-2057
(3)	Maturity dates are 2013-2111

The following table shows the proceeds from sales of securities in the trusts 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,
	2012		2011		2012		2011
Proceeds from sales	$	204	$	294	$	524	$	384
Gross realized gains		3		27		12		29
Gross realized losses		(1)		(8)		(6)		(10)

Net unrealized gains (losses) are included in Regulatory Liabilities Arising from Removal Obligations on the Condensed Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.

Non-Recurring Fair Value Measures – Sempra Energy Consolidated

We discuss non-recurring fair value measures and the associated accounting impact on our investments in RBS Sempra Commodities and Argentina in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report and, with regard to RBS Sempra Commodities, in Note 4 above. We also discuss non-recurring fair value measures and the associated accounting impact on our investment in Rockies Express in Note 4 above.

Rockies Express

In the second quarter of 2012, the noncash impairment charge of $300 million ($179 million after-tax) primarily resulted from the continuing decline in basis differential on REX associated with shale gas production zones coming on line, assumptions related to the re-contracting of the long-term transportation agreements, and the refinancing of the existing project level debt, discussed further below. The fair value measurement was significantly impacted by unobservable inputs (Level 3) as defined by the accounting guidance for fair value measurements, which we discuss in Note 11 of the Notes to Consolidated Financial Statements in the Updated Annual Report. We considered a market participant’s view of the total value for Rockies Express, based on an estimation of the future cash distributions it would be able to generate, adjusted for our 25-percent ownership interest. To estimate future cash distributions, we considered factors impacting Rockies Express’ ability to pay future distributions including:

§   the extent to which future cash flows are hedged by capacity sales contracts and their duration (generally through 2019), as well as the creditworthiness of the various counterparties;

§   Rockies Express’ future financing needs, including the ability to secure borrowings at reasonable rates as well as potentially using operating cash to retire principal;

§   prospects for generating attractive revenues and cash flows beyond 2019, including natural gas’ future basis differentials (driven by the location and extent of future supply and demand) and alternative strategies potentially available to utilize the assets; and

§   discount rates commensurate with the risks inherent in the cash flows.

In the third quarter of 2012, KMI reached an agreement, expected to close in the fourth quarter of 2012, to sell the FTC-mandated asset group, which includes its interest in Rockies Express. Events in the third quarter of 2012 related to this agreement have provided us with additional market participant data. We therefore updated our analysis of the fair value of our investment in Rockies Express as of September 30, 2012 to reflect these additional inputs and recorded an additional impairment charge of $100 million ($60 million after-tax). This fair value measurement in the third quarter was based primarily on the Level 2 input.  We believe this is useful and reliable information, but we considered that it may be impacted by the FTC’s requirement for KMI to sell its interest in Rockies Express. To reflect this uncertainty, our updated analysis included the less subjective Level 2 market participant input as the primary indicator of fair value, with less weight ascribed to value based on estimated discounted cash flows as discussed above and in the table below. The updates to the cash flow analyses used in determining fair value in the second quarter reflected discussions with Tallgrass as to the strategic direction they are planning to take with their equity partners for Rockies Express, as well as additional discussions with other market participants. Tallgrass is expected to be the operator of Rockies Express.

We believe our analysis forms a reasonable estimate of the fair value of Rockies Express. This estimate includes the material input described above, which was generally observable during the period most relevant to our analysis. Regarding the unobservable inputs, significant uncertainties exist with regard to REX’s ability to secure attractive revenues beyond 2019. Accordingly, our analysis suggests that the fair value of our investment in Rockies Express could be materially different from the value we have estimated at this time. For example, if REX is able to sustain the level of revenues currently generated beyond 2019, the value of our investment in Rockies Express would be materially enhanced and the indicated value of our investment in Rockies Express could be significantly higher. Conversely, if REX is unable to sell its transport capacity at sufficient rates or in sufficient volumes beyond 2019, the fair value of our investment in Rockies Express could be materially lower than our carrying amount. Separately, future events involving REX equity could occur and may also provide additional information regarding the fair value of our investment in REX.

Sempra Natural Gas developed the models and scenarios used to measure the fair value of our investment in REX.  This modeling used inputs from external sources as described above and in the table below, as well as internally available data, such as operating and maintenance budgets used for financial planning purposes.  External experts that forecast the future price of natural gas at various physical locations were also engaged to help validate certain scenarios and modeling assumptions.  The fair value measurements were reviewed in detail by Sempra Natural Gas’ financial management, as well as Sempra Energy’s financial management team.

RBS Sempra Commodities

In both the three months and nine months ended September 30, 2011, we reduced our investment in RBS Sempra Commodities to reflect the latest estimates of our expected future cash distributions from the partnership.  This fair value measurement was significantly impacted by unobservable inputs (i.e. Level 3 inputs) as described in the table below.

The following table summarizes significant inputs impacting non-recurring fair value measures related to our investments in REX and RBS Sempra Commodities:

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		Estimated		Fair
		Fair		Value	% of Fair Value		Range of
		Value	Valuation Technique	Hierarchy	Measurement	Inputs Used to Develop Measurement	Inputs
Investment in
Rockies Express		$ 369	Market approach	Level 2	67%	Equity sale offer price	100%
			Probability weighted	Level 3	33%	Combined transportation rate assumption(1)	6% - 78%
			discounted cash flow			Counterparty credit risk on existing contracts	Low
						Operation and maintenance escalation rate	0% - 1%
						Forecasted interest rate on debt to be refinanced	5% - 10%
						Discount rate	8% - 10%
Investment in
RBS Sempra
Commodities		$ 126	Discounted cash flow	Level 3	100%	Future cash distributions	90% - 110%
(1)	Transportation rate beyond existing contract terms as a percentage of current mean REX rates.

NOTE 9. CALIFORNIA UTILITIES' REGULATORY MATTERS

JOINT MATTERS

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. In December 2010, the California Utilities filed their 2012 General Rate Case (GRC) applications to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements will change on an annual basis over the subsequent three-year (2013-2015) period. Both SDG&E and SoCalGas filed revised applications with the CPUC in July 2011. Evidentiary hearings were completed in January 2012, and final briefs reflecting the results from these hearings were filed with the CPUC in May 2012.

In February 2012, the California Utilities filed amendments to update their July 2011 revised applications. With these amendments, SDG&E is requesting a revenue requirement in 2012 of $1.849 billion, an increase of $235 million (or 14.6%) over 2011, of which $67 million is being requested for cost recovery of the incremental wildfire insurance premiums which are not included in the 2011 revenue requirement as set forth in the 2008 GRC. SoCalGas is requesting a revenue requirement in 2012 of $2.112 billion, an increase of $268 million (14.5%) over 2011. The Division of Ratepayer Advocates (DRA) is recommending that the CPUC reduce the utilities’ revenue requirements in 2012 by approximately 5 percent compared to 2011.

Until such time as a final decision for the 2012 GRC is issued, the California Utilities are recording revenues in 2012 based on levels authorized in 2011 plus, for SDG&E, consistent with the recent CPUC decisions for cost recovery for SDG&E’s incremental wildfire insurance premiums, an amount for the recovery of 2012 wildfire insurance premiums. The current CPUC schedule indicates a final decision for the 2012 GRC, which will be made effective retroactive to January 1, 2012, by the end of 2012. However, if the CPUC does not issue a final decision for the 2012 GRC by December 31, 2012, Sempra Energy and the California Utilities will not be able to report the retroactive impact to January 1, 2012 of the final decision in their 2012 financial results, but would reflect the impact in 2013 financial results in the period in which such final decision is issued.

Cost of Capital

A cost of capital proceeding determines a utility’s authorized capital structure and authorized rate of return on rate base (ROR), which is a weighted average of the authorized returns on debt, preferred stock, and common equity (return on equity or ROE). The authorized ROR is the rate that the California Utilities are authorized to use in establishing rates to recover their cost of debt and equity, used to finance their investment in electric and natural gas distribution, natural gas transmission and electric generation assets. In addition, a cost of capital proceeding also addresses the automatic ROR adjustment mechanism which applies market-based benchmarks to determine whether an adjustment to the authorized ROR is required during the interim years between cost of capital proceedings.

SDG&E and SoCalGas filed separate applications with the CPUC in April 2012 to update their cost of capital effective January 1, 2013. Southern California Edison (Edison) and Pacific Gas and Electric Company (PG&E) also filed separate cost of capital applications with the CPUC. SDG&E proposes to adjust its authorized capital structure by increasing the amount of its common equity from 49.0 percent to 52.0 percent. SDG&E also proposes to lower its authorized ROE from 11.1 percent to 11.0 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized ROR from 8.40 percent to 8.15 percent. SoCalGas proposes to adjust its authorized capital structure by increasing the amount of its common equity from 48.0 percent to 52.0 percent. SoCalGas also proposes to increase its authorized ROE from 10.82 percent to 10.9 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized ROR from 8.68 percent to 8.44 percent. In addition, SDG&E proposes to continue its currently approved cost of capital adjustment mechanism which uses a utility bond benchmark. SoCalGas proposes switching from its current cost of capital adjustment mechanism, which is based on U.S. Treasury Bonds, to a mechanism using a utility bond benchmark similar to SDG&E, Edison and PG&E. Both SDG&E and SoCalGas are proposing to add an “off ramp” provision to the adjustment mechanism as a safeguard to protect against extreme changes in interest rates and to allow the CPUC latitude to suspend the annual mechanism if prudent.

The CPUC issued a ruling in June 2012 bifurcating the proceeding. Phase 1 will address each utility’s cost of capital for 2013 with a final decision expected by the end of 2012. Phase 2 will address the cost of capital adjustment mechanisms for SDG&E, SoCalGas, Edison and PG&E, with a final decision expected in the first half of 2013.

SDG&E’s current cost of capital adjustment mechanism benchmark is based on the 12-month average monthly A-rated utility bond yield as published by Moody’s for the 12-month period October through September of each fiscal year. If the 12-month average falls outside of a specified range, then SDG&E’s authorized ROE would be adjusted, upward or downward, by one-half of the difference between the 12-month average and the mid-point of the specified range. In addition, SDG&E’s authorized recovery rate for the cost of debt and preferred stock would also be adjusted to their respective actual weighted average cost. Therefore, SDG&E’s authorized ROR would adjust, upward or downward, as a result of all three adjustments with the new rate going into effect on January 1 following the year in which the benchmark range was exceeded. SDG&E’s current mechanism only applies during the intervening years between scheduled cost of capital updates and does not apply for any change in 2013 given the pending cost of capital application and the expectation of an updated cost of capital effective as of January 1, 2013.

SoCalGas’ Market Indexed Capital Adjustment Mechanism (MICAM) identifies two conditions for determining whether a change in the authorized rate of return is required. Both conditions are based on the 30-year Treasury bond yields – one being the most recent trailing 12-month rolling average yield and the second being the corresponding 12-month forward forecast yield as published by Global Insight. If both conditions fall outside a specified range in a given month, SoCalGas’ authorized ROE would be adjusted, upward or downward, by one-half of the difference between the trailing 12-month rolling average yield and the midpoint of the range, effective January 1 following the year in which both conditions were exceeded. Also, SoCalGas’ authorized recovery rate for the cost of debt and preferred stock would be adjusted to their respective actual weighted average cost. Therefore, SoCalGas’ authorized ROR would adjust, upward or downward, as a result of all three cost adjustments. In the event of such an event occurring, the benchmark interest rate would be reset to the interest rate in effect at the time it was determined that the benchmark range had been exceeded.

In August 2012, the CPUC issued an administrative ruling that confirmed SoCalGas’ participation in Phase 1 of the proceeding and held in abeyance the implementation of SoCalGas’ MICAM triggering event to make the ROE and ROR authorized by the CPUC in this proceeding effective on January 1, 2013.

Natural Gas Pipeline Operations Safety Assessments

Various regulatory agencies, including the CPUC, are evaluating natural gas pipeline safety regulations, practices and procedures. In February 2011, the CPUC opened a forward-looking rulemaking proceeding to examine what changes should be made to existing pipeline safety regulations for California natural gas pipelines. The California Utilities are parties to this proceeding.

In June 2011, the CPUC directed SoCalGas, SDG&E, PG&E and Southwest Gas to file comprehensive implementation plans to test or replace all natural gas transmission pipelines that have not been pressure tested. The California Utilities filed their Pipeline Safety Enhancement Plan (PSEP) with the CPUC in August 2011. The proposed safety measures, investments and estimated costs are not included in the California Utilities’ 2012 GRC requests discussed above.

In December 2011, the assigned Commissioner to the rulemaking proceeding for the pipeline safety regulations ruled that SDG&E’s and SoCalGas’ Triennial Cost Allocation Proceeding (TCAP) would be the most logical proceeding to conduct the reasonableness and ratemaking review of the companies’ PSEP.

In January 2012, the CPUC Consumer Protection and Safety Division (CPSD) issued a Technical Report of the California Utilities’ PSEP.  The report, along with testimony and evidentiary hearings, will be used to evaluate the PSEP in the regulatory process.  Generally, the report found that the PSEP approach to pipeline replacement and pressure testing and other proposed enhancements is reasonable. 

In February 2012, the assigned Commissioner in the TCAP issued a ruling setting a schedule for the review of the SDG&E and SoCalGas PSEP with evidentiary hearings held in August 2012. SDG&E and SoCalGas expect a final decision late in the first half of 2013. In April 2012, the CPUC issued an interim decision in the rulemaking proceeding formally transferring the PSEP to the TCAP and authorizing SDG&E and SoCalGas to establish regulatory accounts to record the incremental costs of initiating the PSEP prior to a final decision on the PSEP. The TCAP proceeding will address the recovery of the costs recorded in the regulatory account.

In April 2012, the CPUC issued a decision expanding the scope of the rulemaking proceeding to incorporate the provisions of California Senate Bill 705, which requires gas utilities to develop and implement a plan for the safe and reliable operation of their gas pipeline facilities. SDG&E and SoCalGas submitted their pipeline safety plans in June 2012. The CPUC must accept, modify or reject the plans by the end of 2012. The CPUC decision also orders the utilities to undergo independent management and financial audits to assure that the utilities are fully meeting their safety responsibilities. CPSD will select the independent auditors and will oversee the audits. A schedule for the audits has not been established.

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 Updated Annual Report.

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.

We provide additional information regarding these incentive mechanisms in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report, and in the updates below.

Energy Efficiency

We expect a final decision on an incentive mechanism for the 2013-2014 program period by the end of 2012. We expect a draft decision on how and if an incentive mechanism should apply to the 2010-2012 program cycle and a final decision on any incentive awards for the 2010-2012 period by the end of 2012. The CPUC issued its latest Order Instituting Rulemaking (OIR) in January 2012 to continue its review of the incentive mechanism.

Natural Gas Procurement

In the first quarter of 2012, the CPUC approved and SoCalGas recorded SoCalGas’ application for its Gas Cost Incentive Mechanism (GCIM) award of $6.2 million for natural gas procured for its core customers during the 12-month period ending March 31, 2011.

In June 2012, SoCalGas applied to the CPUC for approval of a GCIM award of $5.4 million for natural gas procured for its core customers during the 12-month period ending March 31, 2012. SoCalGas expects a CPUC decision in the first half of 2013.

SDG&E MATTERS

San Onofre Nuclear Generating Station (SONGS)

SDG&E has a 20-percent ownership interest in San Onofre Nuclear Generating Station (SONGS), a 2,150-MW nuclear generating facility near San Clemente, California. SONGS is operated by Edison and is subject to the jurisdiction of the Nuclear Regulatory Commission (NRC) and the CPUC.

In 2005, the CPUC authorized a project to install four new steam generators in Units 2 and 3 at SONGS and remove and dispose of their predecessor generators. Edison completed the installation of these steam generators in 2010 and 2011 for Units 2 and 3, respectively. In January 2012, a water leak occurred in the Unit 3 steam generator which caused it to be shut down. Edison conducted inspection testing and determined that the water leak was the result of excessive wear from tube-to-tube contact. During a planned maintenance and refueling outage on the Unit 2 steam generators in February 2012, inspections found high levels of unexpected wear in some heat transfer tubes of the Unit 2 steam generators. As of today, both Units 2 and 3 remain offline.

Any remedial action that will permit restart of one or both of the Units will need to be approved by the NRC. In March 2012, the NRC issued a Confirmatory Action Letter (CAL) that required NRC permission to restart Unit 2 and Unit 3 and outlined actions that Edison must complete before permission to restart either Unit may be sought. The NRC could also choose to impose additional inspections and assessment processes that could result in significant costs or additional delay. In October 2012, Edison submitted a plan to the NRC to restart and operate Unit 2 at a reduced power level for five months and then shut it down for further inspection. The plan submitted to the NRC does not address Unit 3. It is not clear at this time whether Unit 3 can be restarted without extensive additional repairs, and Edison has not indicated when it believes Unit 3 may be ready to restart operations. The timing of the restart of either of the Units is dependent upon approval by the NRC. The NRC may employ other procedures before making any determination about whether to grant permission pursuant to the terms of the CAL. It is also possible that one or more amendments to the NRC operating license for SONGS might be required (whether or not as a prerequisite to return a Unit to safe operation). There is no set or predetermined time period for such processes, and, accordingly, there can be no assurance about the length of time the NRC may take to review any request to restart submitted by Edison under the CAL or whether any such request would be granted in whole or in part.

Through September 30, 2012, SDG&E’s proportional investment in the steam generators was approximately $180 million. These investment amounts remain subject to CPUC review upon submission of Edison’s final costs for the overall project.

During the unscheduled outage at SONGS, SDG&E has procured replacement power, the cost of which is fully recovered in revenues subject to a reasonableness review by the CPUC. Replacement power costs for outages associated with the unscheduled SONGS outage (commencing in 2012 on January 31 for Unit 3 and March 5 for Unit 2) through September 30, 2012 were approximately $54 million. Total replacement power costs will not be known until the Units are returned to service.

Currently, SDG&E is collecting in customer rates its share of the operating costs, depreciation and return on its investment in SONGS. For the nine-month period ended September 30, 2012, SDG&E has recognized (and collected through customer rates) an estimated $153 million of revenue associated with its investment in SONGS and operating costs. At September 30, 2012, SDG&E’s weighted average rate base investment in SONGS was approximately $220 million and its net book investment, including construction work in progress and nuclear fuel was $485 million.

In November 2012, the CPUC issued an Order Instituting Investigation (OII) into the SONGS outage pursuant to California Public Utilities Code Section 455.5 to determine whether Edison and SDG&E should remove from customer rates some or all revenue requirement associated with the portion of the facility that is out of service. This OII will consolidate all SONGS issues from related regulatory proceedings and consider the appropriate cost recovery for SONGS, including among other costs, the cost of the steam generator replacement project, replacement power costs, capital expenditures, operation and maintenance costs and seismic study costs. The OII requires that all costs related to SONGS incurred since January 1, 2012 be tracked in a separate memorandum account, with all revenues collected in recovery of such costs subject to refund, and will address the extent to which such revenues, if any, will be required to be refunded to customers.

Under Section 455.5, any determination to adjust rates would be made after hearings are conducted in connection with Edison’s next general rate case. If, after investigation and hearings, the CPUC were to require SDG&E to reduce rates as a result of a Unit being out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation. Notwithstanding the requirements of Section 455.5, the CPUC may institute other proceedings relating to the impact of the extended outage at SONGS and its potential effects on rates.

The steam generators were designed and supplied by Mitsubishi Heavy Industries (MHI) and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. On July 18, 2012, the NRC issued a report providing the result of the inspection performed by the Augmented Inspection Team (AIT). The inspection concluded that faulty computer modeling that inadequately predicted conditions in the steam generators at SONGS and manufacturing issues contributed to excessive wear of the components. The most probable causes of the tube-to-tube wear were a combination of higher than predicted thermal/hydraulic conditions and changes in the manufacturing of the Unit 3 steam generators. This report also identified a number of yet unresolved issues that are continuing to be examined. Edison’s purchase contract with MHI states that MHI’s liability under the purchase agreement is limited to $137 million and excludes consequential damages, defined to include the cost of replacement power. Such limitations in the contract are subject to applicable exceptions. In September 2012, Edison submitted an invoice on behalf of all owners to MHI in the amount of $45 million for certain steam generator repair costs incurred. Edison expects to continue to invoice MHI for any additional costs incurred.

SDG&E is a named insured on the Edison insurance policies covering SONGS. These policies, issued by Nuclear Electric Insurance Limited (NEIL), cover nuclear property and non-nuclear property damage at the SONGS facility, as well as accidental outage insurance. Edison has placed NEIL on notice of potential claims for loss recovery. On October 1, 2012, Edison submitted to NEIL a Partial Proof of Loss on behalf of Edison, SDG&E and the City of Riverside in connection with the outages of SONGS Units 2 and 3. The NEIL policies contain a number of exclusions and limitations that may reduce or eliminate coverage. SDG&E will assist Edison in pursuing claims recoveries from NEIL, as well as warranty claims with MHI, but there is no assurance that SDG&E will recover all or any of its applicable costs pursuant to these arrangements.

In light of the aftermath and the significant safety events at the Fukushima Daiichi nuclear plant in Japan resulting from the earthquake and tsunami in March 2011, the NRC plans to perform additional operation and safety reviews of nuclear facilities in the United States. The lessons learned from the events in Japan and the results of the NRC reviews may materially impact future operations and capital requirements at nuclear facilities in the United States, including the operations and capital requirements at SONGS.

Edison is also addressing a number of other regulatory and performance issues at SONGS, and the NRC has required Edison to take actions to provide greater assurance of compliance by SONGS personnel. Edison continues to implement plans and address the identified issues, however a number of these issues remain outstanding. To the extent that these issues persist, it is likely that additional action will be required by Edison, which may result in increased SONGS operating costs and/or materially adversely impacted operations. Currently, SDG&E is allowed to fully offset its share of SONGS operating costs in revenue. If further action is required, it may result in an increase in SDG&E’s Operation and Maintenance expense, with any increase being fully offset in Operating Revenues – Electric.

We provide more information about SONGS in Note 10 and in Notes 6, 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Power Procurement and Resource Planning

Renewable Energy

SDG&E is subject to the Renewables Portfolio Standard (RPS) Program administered by both the CPUC and the California Energy Commission (CEC), which requires each California utility to procure 33 percent of its annual electric energy requirements from renewable energy sources by 2020, with an average of 20 percent required from January 1, 2011 to December 31, 2013; 25 percent by December 31, 2016; and 33 percent by December 31, 2020. The CPUC began a rulemaking in May 2011 to address the implementation of the 33% RPS Program. We discuss the RPS Program further in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

South Orange County Reliability Enhancement

SDG&E filed an application with the CPUC in May 2012 for a Certificate of Public Convenience and Necessity (CPCN) to construct the South Orange County Reliability Enhancement project. The purpose of the project is to enhance the capacity and reliability of SDG&E’s electric service to the south Orange County area. The proposed project primarily includes replacing and upgrading approximately eight miles of transmission lines and rebuilding and upgrading a substation at an existing site. SDG&E expects a final CPUC decision approving the estimated $473 million project in the second half of 2013. SDG&E obtained approval for the project from the ISO in May 2011. The project is planned to be in service by the second half of 2017.

Incremental Insurance Premium Cost Recovery

In December 2010, the CPUC approved SDG&E’s request for a $29 million revenue requirement for the recovery of the incremental increase in its general liability and wildfire liability insurance premium costs for the July 2009/June 2010 policy period. In its decision approving this cost recovery, the CPUC also authorized SDG&E to request recovery of any incremental insurance premiums for future policy periods through December 31, 2011, with a $5 million deductible applied to each policy renewal period. This approval was in response to a request filed by SDG&E with the CPUC in August 2009 seeking authorization to recover higher liability insurance premiums (amounts in excess of those authorized to be recovered in the 2008 GRC), which SDG&E began incurring commencing July 1, 2009, and any losses realized due to higher deductibles associated with the new policies. SDG&E made the filing under the CPUC’s rules allowing utilities to seek recovery of significant cost increases incurred between GRC filings that meet certain criteria, subject to a $5 million deductible per event.

In December 2011, the CPUC approved SDG&E’s request for an incremental revenue requirement of $63 million for the July 2010/June 2011 policy period. In May 2012, the CPUC approved SDG&E’s request for a $28 million revenue requirement for the first six months of the July 2011/June 2012 policy period.

In the CPUC’s December 2010 decision, discussed above, the CPUC directed SDG&E to include in its 2012 GRC application the amount of the incremental wildfire insurance premiums it would be seeking recovery for in rates subsequent to December 31, 2011. SDG&E’s 2012 GRC application does request $67 million of revenue requirement for cost recovery of wildfire insurance premiums in 2012. As a decision on SDG&E’s 2012 GRC application is pending with the CPUC, and based on the CPUC’s rulings for the recovery of the cost of the incremental wildfire insurance premiums incurred since July 2009, SDG&E’s 2012 revenue through September 30, 2012 reflects the expected recovery of the cost of the incremental wildfire insurance premiums incurred in the current year.

Excess Wildfire Claims Cost Recovery

SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC in August 2009 proposing a new mechanism for the future recovery of all wildfire-related expenses for claims, litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC for recovery in distribution rates. This application was made jointly with Edison and PG&E. In July 2010, the CPUC approved SDG&E’s and SoCalGas’ requests for separate regulatory memorandum accounts to record the subject expenses while the application is pending before the CPUC. Several parties protested the original application and, in response, the four utilities jointly submitted an amended application in August 2010. In November 2011, Edison and PG&E requested to withdraw from the joint utility application due, in part, to the delays in the proceeding. In January 2012, the CPUC granted their requests to withdraw and held evidentiary hearings for SDG&E and SoCalGas, both of which are still moving forward with the application. Legal briefs were completed in March 2012.

In October 2012, the Administrative Law Judge’s (ALJ) draft decision (Proposed Decision or PD) and the Assigned Commissioner’s alternate draft decision (Alternate Decision or AD) in this proceeding were issued. The PD rejects SDG&E’s and SoCalGas’ request for a new balancing account and cost recovery mechanism and directs both SDG&E and SoCalGas to close the regulatory memorandum account that was previously authorized by the CPUC in July 2010 and remove any amount recorded to it. The PD does, however, state that should SDG&E continue to pursue recovery of such costs incurred, there are other established mechanisms that SDG&E can utilize to seek recovery. The AD approves SDG&E’s and SoCalGas’ request for a new balancing account and cost recovery mechanism but only for wildfire events that occur after July 2010, the effective date of the CPUC decision authorizing the regulatory memorandum account. The AD also directs SDG&E to remove any amounts recorded in the regulatory memorandum account associated with the 2007 wildfires. Under the terms of the AD, for wildfires for which the utility is found not to be at fault, SDG&E and SoCalGas may seek recovery in rates of 90 percent of costs incurred for payments made to settle claims associated with inverse condemnation which exceed the sum of $10 million per wildfire, their insurance coverage, and recoveries made from other third parties. For any costs incurred for wildfire events occurring prior to July 2010, the AD allows the utility to use the existing Z-factor application process to request recovery of such costs. A Z-factor application process allows utilities to seek recovery of significant cost increases incurred between GRC filings. We expect a final CPUC decision in the current proceeding by the end of 2012.

Following the issuance of the PD and the AD and consistent with CPUC rules and procedures, SDG&E requested an ex parte meeting with the Assigned Commissioner and staff. The request was granted, and the ex parte meeting was held on October 29, 2012. At the meeting, SDG&E provided information to the Assigned Commissioner addressing key issues from the AD that SDG&E believes contradict prior CPUC rulings and decisions. On November 5, 2012, SDG&E provided the CPUC with written comments and suggested changes to the AD. While there can be no assurance that the Assigned Commissioner will amend the AD, given the relevant regulatory and statutory standards and the issues discussed at the ex parte meeting, SDG&E has concluded that it remains probable that SDG&E will be permitted to recover from ratepayers substantially all reasonably incurred costs associated with the 2007 wildfires that exceed amounts recovered from its insurance coverage and other responsible third parties. SDG&E intends to continue to pursue recovery of such costs in this proceeding or, if necessary, in a future application, such as the Z-factor application noted in both the PD and the AD.

SDG&E will continue to assess the recovery of these excess wildfire costs from ratepayers. Should SDG&E conclude that the amount of recovery from ratepayers is no longer reasonably estimable or that recovery is no longer probable, including as a result of the CPUC’s failure to adopt a final decision in this proceeding that supports future recovery from ratepayers, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that such recovery was no longer probable or reasonably estimable as of September 30, 2012, the resulting after-tax charge against earnings would have been approximately $175 million. In addition, in periods following any such conclusion, SDG&E’s earnings will be adversely impacted by increases in the estimated cost to settle pending wildfire claims.

We provide additional information about 2007 wildfire litigation costs and their recovery in Note 10.

East County Substation

In June 2012, the CPUC approved SDG&E’s application for authorization to proceed with the East County Substation project, estimated to cost $435 million. The Bureau of Land Management (BLM) issued its record of decision in August 2012. SDG&E expects to begin construction in the first half of 2013 and the substation to be placed in service in 2014. We provide additional information on the project in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

SOCALGAS MATTER

Aliso Canyon Natural Gas Storage Compressor Replacement

In September 2009, SoCalGas filed an application with the CPUC requesting approval to replace certain obsolete natural gas turbine compressors used in the operations of SoCalGas’ Aliso Canyon natural gas storage reservoir, with a new electric compressor station. In April 2012, the CPUC issued a draft environmental impact report (EIR) for the project concluding that no significant or unavoidable adverse environmental impacts have been identified from the construction or operation of the proposed project. We expect a final EIR and CPUC decision on the estimated $200 million project in 2013.

We discuss additional matters affecting our California Utilities in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

NOTE 10. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

We accrue losses for legal proceedings 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 coverages and could materially adversely affect our business, cash flows, results of operations, and financial condition. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.

At September 30, 2012, Sempra Energy’s accrued liabilities for material legal proceedings, on a consolidated basis, were $427 million. At September 30, 2012, accrued liabilities for material legal proceedings for SDG&E and SoCalGas were $411 million and $5 million, respectively. At September 30, 2012, liabilities of $411 million at Sempra Energy and SDG&E were related to wildfire litigation discussed below.

SDG&E

2007 Wildfire Litigation

In October 2007, San Diego County experienced several catastrophic wildfires. Reports issued by the California Department of Forestry and Fire Protection (Cal Fire) concluded that two of these fires (the Witch and Rice fires) were SDG&E “power line caused” and that a third fire (the Guejito fire) occurred when a wire securing a Cox Communications’ (Cox) fiber optic cable came into contact with an SDG&E power line “causing an arc and starting the fire.” Cal Fire reported that the Rice fire burned approximately 9,500 acres and damaged 206 homes and two commercial properties, and the Witch and Guejito fires merged and eventually burned approximately 198,000 acres, resulting in two fatalities, approximately 40 firefighters injured and an estimated 1,141 homes destroyed.

A September 2008 staff report issued by the CPUC’s CPSD 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 have 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. These include owners and insurers of properties that were destroyed or damaged in the fires and government entities seeking recovery of firefighting, emergency response, and environmental costs. They assert 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.

In October 2010, the Court of Appeal affirmed the trial court’s ruling that these claims must be pursued in individual lawsuits, rather than as class actions on behalf of all persons who incurred wildfire damages. In February 2011, the California Supreme Court denied a petition for review of the affirmance. No trial date is currently scheduled.

SDG&E filed cross-complaints against Cox seeking indemnification for any liability that SDG&E might incur in connection with the Guejito fire, two SDG&E contractors seeking indemnification in connection with the Witch fire, and one SDG&E contractor seeking indemnification in connection with the Rice fire. SDG&E has entered into settlement agreements with Cox and the three contractors for a total of approximately $824 million. Among other things, the settlement agreements provide that SDG&E will defend and indemnify Cox and the three contractors against all compensatory damage claims and related costs arising out of the wildfires.

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 has paid or will 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.

The wildfire litigation also includes claims of 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 settled the claims of approximately 4,700 of these plaintiffs, including all of the government entities. Approximately 1,550 of the approximately 1,750 remaining individual and business plaintiffs have submitted settlement demands and damage estimates totaling approximately $1.4 billion. SDG&E does not expect significant additional plaintiffs to file lawsuits given the applicable statutes of limitation, but does expect to receive additional settlement demands and damage estimates from existing plaintiffs as settlement negotiations continue. SDG&E has established reserves for the wildfire litigation as we discuss below.

SDG&E’s settled claims and defense costs have exceeded its $1.1 billion of liability insurance coverage and the approximately $824 million received or receivable from third parties to date. It expects that its wildfire reserves and amounts paid to resolve wildfire claims will continue to increase as it obtains additional information.

As we discuss in Note 9, upon consideration of the relevant regulatory and statutory standards and the issues discussed at an ex parte meeting with the CPUC Assigned Commissioner, SDG&E has concluded that it is probable that it will be permitted to recover from its utility customers substantially all reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and the amounts recovered from other responsible parties. Accordingly, although such recovery will require future regulatory actions, at September 30, 2012, Sempra Energy and SDG&E have recorded assets of $326 million in Regulatory Assets Arising From Wildfire Litigation Costs on their Condensed Consolidated Balance Sheets, including $292 million related to CPUC operations, which represents the amount substantially equal to the aggregate amount it has paid or reserved for payment for the resolution of wildfire claims and related costs in excess of its liability insurance coverage and amounts received or receivable from third parties. SDG&E will increase the regulatory assets as additional amounts are paid or reserves are recorded.

SDG&E will continue to assess the recovery of these excess wildfire costs from ratepayers. Should SDG&E conclude that the amount of recovery from ratepayers is no longer reasonably estimable or that recovery 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 such recovery was no longer probable or reasonably estimable as of September 30, 2012, the resulting after-tax charge against earnings would have been approximately $175 million. In addition, in periods following any such conclusion, SDG&E’s earnings will be adversely impacted by increases in the estimated cost to settle pending wildfire claims. We provide additional information about excess wildfire claims cost recovery in Note 9.

SDG&E’s cash flow may be materially adversely affected due to the timing differences between the resolution of claims and the recoveries from utility customers, which may extend over a number of years. Also, recovery from customers will require future regulatory actions, and a failure to obtain substantial or full recovery, 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 position, cash flows and results of operations.

SDG&E will continue to gather information to evaluate and assess the remaining wildfire claims and the likelihood, amount and timing of related recoveries from utility customers and will make appropriate adjustments to wildfire reserves and the related regulatory assets as additional information becomes available.

Since 2010, as liabilities for wildfire litigation have become reasonably estimable in the form of settlement demands, damage estimates, and other damage information, SDG&E has recorded related reserves as a liability. The impact of this liability at September 30, 2012 is offset by the recognition of regulatory assets, as discussed above, for reserves in excess of the insurance coverage and recoveries from third parties. Due primarily to the recovery from two of SDG&E’s contractors, the impact of the reserves on SDG&E’s and Sempra Energy’s after-tax earnings was an increase of $1 million and a decrease of $5 million for the three months ended September 30, 2012 and 2011, respectively, and a decrease of $4 million and $7 million for the nine months ended September 30, 2012 and 2011, respectively. At September 30, 2012, wildfire litigation reserves were $411 million ($284 million in current and $127 million in long-term). Additionally, through September 30, 2012, SDG&E has expended $187 million (excluding amounts covered by insurance and amounts recovered from other responsible third parties) to pay costs associated with the settlement of wildfire claims.

Sunrise Powerlink Electric Transmission Line

SDG&E commenced construction on the Sunrise Powerlink in the fall of 2010. The Sunrise Powerlink is a new 117-mile, 500-kilovolt (kV) electric transmission line between the Imperial Valley and the San Diego region, along a route that generally runs south of the Anza-Borrego Desert State Park. Construction of the transmission line has been completed and the line was energized and placed in service in June 2012.

The Sunrise Powerlink project was originally approved by the CPUC in December 2008, including approval of the environmental impact review conducted jointly with the BLM. The CPUC subsequently denied or dismissed all requests for rehearing of its approval of the project. In February 2011, the California Supreme Court denied a petition filed jointly by the Utility Consumers’ Action Network (UCAN) and the Center for Biological Diversity/Sierra Club challenging the CPUC’s decision with regard to implementation of the California Environmental Quality Act (CEQA).

In January 2009, the BLM issued its decision approving the portions of the project, route and environmental review within its jurisdiction. The Interior Board of Land Appeals subsequently denied or dismissed all administrative appeals that were filed challenging the BLM’s approval of the project.

In February 2010, parties opposed to the project filed a lawsuit in Federal District Court in San Diego alleging that the BLM failed to properly address the environmental impacts of the approved Sunrise Powerlink route and the related potential development of renewable resources in east San Diego County and Imperial County. In July 2012, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court’s grant of the defendants’ motion for summary judgment.

In July 2010, the United States Forest Service (USFS) issued its decision approving the portions of the project, route and environmental review within its jurisdiction. The USFS subsequently denied all administrative appeals challenging its approval of the project.

The CPUC and BLM jointly approved the final Project Modification Report for Sunrise Powerlink in September 2010, accepting all of the proposed modifications to the approved route and finding that no additional environmental review was required. In March 2011, opponents of the Sunrise Powerlink filed a petition with the California Supreme Court challenging the CPUC’s acceptance of the Project Modification Report. The California Supreme Court denied the petition in April 2011.

In January 2011, project opponents filed a lawsuit in Federal District Court in San Diego alleging that the federal approvals for construction of the project on USFS land and BLM land violated the National Environmental Policy Act and other federal environmental laws. In June 2012, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court’s denial of plaintiffs’ motion for a preliminary injunction.

In February 2011, opponents of the Sunrise Powerlink 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 CEQA. The Superior Court denied the plaintiffs’ petition in July 2012, and the plaintiffs have appealed.

September 2011 Power Outage

In September 2011, a power outage lasting approximately 12 hours affected millions of people from Mexico to southern Orange County, California. Within several days of the outage, several SDG&E customers filed a class action lawsuit in Federal District Court in San Diego against Arizona Public Service Company, Pinnacle West, and SDG&E alleging that the companies failed to prevent the outage. The lawsuit seeks recovery of unspecified amounts of damages, including punitive damages. In July 2012, the court granted SDG&E’s motion to dismiss the punitive damages request and dismissed Arizona Public Service Company and Pinnacle West from the lawsuit. In addition, more than 7,000 customers’ claims, primarily related to food spoilage, have been submitted directly to SDG&E. The Federal Energy Regulatory Commission (FERC) and North American Electric Reliability Corp. (NERC) conducted a joint inquiry to determine the cause of the power failure and issued a report in May 2012 regarding their findings. The report does not include any findings of failure on SDG&E’s part that led to the power failure.

Smart Meters Patent Infringement Lawsuit

In October 2011, SDG&E was sued by a Texas design and manufacturing company in Federal District Court 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.

SoCalGas

SoCalGas, along with Monsanto Co., Solutia, Inc., Pharmacia Corp., and Pfizer, Inc., are defendants in five 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 two of the five lawsuits for an amount that is not significant and has been recorded.

Sempra Natural Gas

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 alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and seeks damages of $56.7 million. Liberty filed a counterclaim alleging breach of contract in the inducement and seeks damages of more than $215 million.

Sempra Mexico

Sempra Mexico has been engaged in a long-running land dispute relating to property adjacent to its Energía Costa Azul liquefied natural gas (LNG) terminal near Ensenada, Mexico. The adjacent property is not required by environmental or other regulatory permits 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. In February 2011, based on a complaint by the claimant, the new Ensenada Mayor attempted 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. 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 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.

Additionally, several administrative challenges are pending in Mexico before the Mexican environmental protection agency (SEMARNAT) and/or 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. Also, there are two real property cases pending 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. Sempra Mexico expects further proceedings on each of these matters.

In July 2012, a Mexicali state court issued a ruling declaring the purchase contract by which Termoeléctrica de Mexicali (TDM) acquired the property on which the facility is located to be invalid, on the grounds that the proceeding in which the seller acquired title was invalid. TDM has appealed the ruling, and it is not enforceable while the appeal is pending. In accordance with Mexican law, TDM remains in possession of the property, and its operations have not been affected.

Other Litigation

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 December 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 resolves all issues with regard to sales between the California Department of Water Resources (DWR) 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.

Sempra Energy and several subsidiaries, along with three oil and natural gas companies, the City of Beverly Hills, and the Beverly Hills Unified School District, were defendants in toxic tort lawsuits filed beginning in 2003 in Los Angeles County Superior Court by approximately 1,000 plaintiffs. These lawsuits claimed that various emissions resulted in cancer or fear of cancer. In November 2006, the court granted the defendants’ summary judgment motions based on lack of medical causation for the 12 initial plaintiffs scheduled to go to trial first. The court also granted summary judgment excluding punitive damages. In June 2010, a tentative settlement as to Sempra Energy and its subsidiaries was reached for an amount that was not significant and was recorded. The settlement was finalized in August 2012.

As described in Note 4, we hold a noncontrolling interest in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. In March 2012, RBS received a letter from the United Kingdom’s Revenue and Customs Department (HMRC) regarding a value-added-tax (VAT) matter related to RBS Sempra Energy Europe (RBS SEE), a former indirect subsidiary of RBS Sempra Commodities that was sold to JP Morgan. The letter states that HMRC is conducting a number of investigations into VAT tax refund claims made by various businesses related to the purchase and sale of carbon credit allowances. The letter also states that HMRC believes it has grounds to deny RBS the ability to reduce its VAT liability by VAT paid during 2009 because it 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 an assessment of £86 million for the VAT paid in connection with these transactions and identified several options for responding, including requesting a review by HMRC and appealing to an independent tribunal. HMRC indicated that the assessment was issued on a protective basis as discussion about the issues is continuing.

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

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 $12.2 billion of secondary financial protection (SFP). If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $375 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. SDG&E’s contribution would be up to $47 million. This amount is subject to an annual maximum of $7 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. In addition, the SONGS owners have up to $490 million insurance coverage for outage expenses and replacement power costs due to accidental property damage. This coverage is limited to $3.5 million per week for the first 52 weeks, then $2.8 million per week for up to 110 additional weeks. There is a 12-week waiting period deductible. These insurance coverages are provided through a mutual insurance company. Insured members are subject to retrospective premium assessments. SDG&E could be assessed up to $9.7 million.

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.

We provide additional information about SONGS in Note 9.

CONTRACTUAL COMMITMENTS

We discuss below significant changes in the first nine months of 2012 to contractual commitments discussed in Note 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Natural Gas Contracts

SoCalGas’ natural gas purchase and pipeline capacity commitments have increased by $232 million since December 31, 2011. The increase, primarily due to new natural gas purchase and pipeline capacity contracts of $591 million, is offset by a reduction of $359 million from fulfillment of commitments in the first nine months of 2012. Net future payments are expected to decrease by $231 million in 2012 and increase by $307 million in 2013, $67 million in 2014, $34 million in 2015, $4 million in 2016 and $51 million thereafter compared to December 31, 2011.

Sempra Mexico’s natural gas purchase commitments have decreased by $128 million since December 31, 2011, primarily due to changes in forward prices and fulfillment of commitments in the first nine months of 2012. Net future payments are therefore expected to decrease by $81 million in 2012, $22 million in 2013 and $25 million in 2014 compared to December 31, 2011.

Sempra Natural Gas’ natural gas purchase and storage capacity commitments have increased by $73 million since December 31, 2011, primarily due to new storage capacity contracts in the first nine months of 2012. Net future payments are expected to decrease by $7 million in 2012, and increase by $14 million in 2013, $10 million in 2014, $11 million in 2015, $11 million in 2016 and $34 million thereafter compared to December 31, 2011.

LNG Purchase Agreements

At September 30, 2012, Sempra Natural Gas has various purchase agreements with major international companies for the supply of LNG to the Energía Costa Azul and Cameron receipt terminals. We discuss these agreements further in Note 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report. Sempra Natural Gas’ commitments under all LNG purchase agreements, reflecting changes in forward prices since December 31, 2011 and actual transactions for the first nine months of 2012, are expected to decrease by $384 million in 2012, $9 million in 2013, $18 million in 2014, $27 million in 2015, $33 million in 2016 and $523 million thereafter compared to December 31, 2011.

The LNG commitment amounts above are based on Sempra Natural Gas’ commitment to accept the maximum possible delivery of cargoes under the agreements. Actual LNG purchases for the nine months ended September 30, 2012 have been significantly lower than the maximum amounts possible.

Purchased-Power Contracts

SDG&E’s commitments under purchased-power contract commitments have increased by $1.6 billion since December 31, 2011. The increase is primarily due to new contracts associated with renewable energy development projects and changes in expected prices. Net future payments are therefore expected to decrease by $47 million in 2012, and increase by $18 million in 2013, $61 million in 2014, $66 million in 2015, $67 million in 2016 and $1.4 billion thereafter compared to December 31, 2011.

Sempra South American Utilities’ purchased-power contracts have increased by $96 million since December 31, 2011, primarily due to foreign currency translation (as the contracts are denominated in the local currency), offset by changes in expected prices and fulfillment of commitments in the first nine months of 2012. Net future payments for the purchased-power contracts at Luz del Sur are expected to decrease by $291 million in 2012, increase by $15 million in 2013 and $2 million in 2014, decrease by $1 million in 2015, and to increase by $8 million in 2016 and $105 million thereafter.  Net future payments for the purchased-power contracts at Chilquinta Energía are expected to decrease by $205 million in 2012, and increase by $28 million in 2013, $32 million in 2014, $34 million in 2015, $34 million in 2016 and $335 million thereafter. These amounts are based on estimated future purchases at current contracted rates, as the contracts require no minimum purchases.

Operating Leases

Sempra Renewables entered into a land lease for the Copper Mountain Solar 2 project, which lease expires in 2054. Future payments on the lease are $2 million in 2013, $2 million in 2014, $2 million in 2015, $2 million in 2016 and $57 million thereafter.

Construction and Development Projects

In the first nine months of 2012, significant increases to contractual commitments at SDG&E were $34 million for electric transmission and distribution systems, $11 million for infrastructure improvements for natural gas transmission and distribution operations and $196 million for construction costs associated with the ECO Substation. The future payments for these contractual commitments are expected to be $62 million in 2012, $159 million in 2013 and $20 million in 2014.

In connection with the completion of the Sunrise Powerlink project, the CPUC required that SDG&E establish a fire mitigation fund to minimize the risk of fire as well as reduce the potential wildfire impact on residences and structures near the Sunrise Powerlink.  The future payments for these contractual commitments are expected to be approximately $3 million per year, subject to escalation of 2 percent per year, for 58 years. At September 30, 2012, the present value of these future payments of $116 million has been recorded as a regulatory asset as the amounts represent a cost that will be recovered from customers in the future, and the related liability was $113 million.

In the first nine months of 2012, significant increases to contractual commitments at SoCalGas were $60 million for construction and infrastructure improvements for natural gas transmission and distribution operations. The payments for these contractual commitments are all expected to be in 2012.

Other

In July 2012, SDG&E received $85 million from Citizens Sunrise Transmission, LLC (Citizens), a subsidiary of Citizens Energy Corporation. For this payment, under the terms of the agreement with Citizens, SDG&E will provide Citizens with access to a segment of the Sunrise Powerlink transmission line known as the Border-East transmission line equal to 50 percent of the transfer capacity of this portion of the line for a period of 30 years. After the 30-year contract term, the transfer capability will revert to SDG&E. SDG&E will amortize deferred revenues from the use of the transfer capability over the 30-year term, and depreciation for 50 percent of the Border-East transmission line segment will be accelerated from an estimated 58-year life to 30 years.

NOTE 11. 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 operates electric transmission and distribution utilities in Chile and Peru, and owns interests in utilities in Argentina. We are currently pursuing the sale of our interests in the Argentine utilities, which we discuss further in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

4.   Sempra Mexico develops, owns and operates, or holds interests in, natural gas transmission pipelines and propane systems, a natural gas distribution utility, electric generation facilities, including wind, and a terminal for the import of LNG 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, Nevada and Pennsylvania to serve wholesale electricity markets in the United States.

6.   Sempra Natural Gas develops, owns and operates, or holds interests in, a natural gas-fired electric generation plant, 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 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.

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 and the former commodities-marketing businesses.

SEGMENT INFORMATION
(Dollars in millions)
	Three months ended September 30,								Nine months ended September 30,
	2012				2011				2012				2011
REVENUES
SDG&E	$	1,092	44	%	$	868	34	%	$	2,706	39	%	$	2,405	32	%
SoCalGas		728	29			844	33			2,328	33			2,776	37
Sempra South American Utilities		356	14			345	13			1,061	15			706	10
Sempra Mexico		181	7			183	7			434	6			561	8
Sempra Renewables		27	1			7	―			49	1			17	―
Sempra Natural Gas		294	12			455	18			761	11			1,340	18
Adjustments and eliminations		―	―			(1)	―			(1)	―			(1)	―
Intersegment revenues(1)		(171)	(7)			(125)	(5)			(359)	(5)			(372)	(5)
Total	$	2,507	100	%	$	2,576	100	%	$	6,979	100	%	$	7,432	100	%
INTEREST EXPENSE
SDG&E	$	49			$	37			$	124			$	104
SoCalGas		17				17				51				52
Sempra South American Utilities		6				9				22				23
Sempra Mexico		4				4				10				15
Sempra Renewables		6				4				13				9
Sempra Natural Gas		26				22				72				62
All other		62				58				185				174
Intercompany eliminations		(44)				(33)				(125)				(95)
Total	$	126			$	118			$	352			$	344
INTEREST INCOME
SoCalGas	$	―			$	1			$	―			$	1
Sempra South American Utilities		3				6				11				18
Sempra Mexico		4				3				10				7
Sempra Renewables		2				―				3				―
Sempra Natural Gas		15				8				41				25
All other		―				(2)				―				1
Intercompany eliminations		(19)				(10)				(51)				(31)
Total	$	5			$	6			$	14			$	21
DEPRECIATION AND AMORTIZATION
SDG&E	$	128	46	%	$	108	43	%	$	359	45	%	$	316	43	%
SoCalGas		91	33			83	33			268	33			246	34
Sempra South American Utilities		15	5			14	6			42	5			27	4
Sempra Mexico		15	5			15	6			46	6			46	6
Sempra Renewables		4	1			1	―			10	1			4	1
Sempra Natural Gas		24	9			26	10			69	9			79	11
All other		3	1			4	2			9	1			11	1
Total	$	280	100	%	$	251	100	%	$	803	100	%	$	729	100	%
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	38			$	63			$	151			$	154
SoCalGas		37				41				105				106
Sempra South American Utilities		27				18				57				30
Sempra Mexico		21				(7)				44				24
Sempra Renewables		(12)				(9)				(47)				(22)
Sempra Natural Gas		(45)				27				(171)				97
All other		(17)				(58)				(91)				(100)
Total	$	49			$	75			$	48			$	289

SEGMENT INFORMATION (Continued)
(Dollars in millions)
		Three months ended September 30,								Nine months ended September 30,
		2012				2011				2012				2011
EQUITY EARNINGS (LOSSES)
Earnings (losses) recorded before tax:
Sempra Renewables		$	(6)			$	(6)			$	(7)			$	(6)
Sempra Natural Gas			(87)				10				(366)				29
All other			(1)				(16)				(2)				(27)
Total		$	(94)			$	(12)			$	(375)			$	(4)
Earnings recorded net of tax:
Sempra South American Utilities		$	―			$	―			$	―			$	23
Sempra Mexico			10				6				29				22
Total		$	10			$	6			$	29			$	45
EARNINGS (LOSSES)
SDG&E(2)		$	174	65	%	$	113	39	%	$	374	66	%	$	273	26	%
SoCalGas(2)			71	26			81	28			190	34			208	20
Sempra South American Utilities			40	15			50	17			118	21			386	37
Sempra Mexico			54	20			47	16			134	24			121	12
Sempra Renewables			13	5			1	1			47	8			9	1
Sempra Natural Gas			(68)	(25)			41	14			(260)	(46)			151	14
All other			(16)	(6)			(44)	(15)			(37)	(7)			(102)	(10)
Total		$	268	100	%	$	289	100	%	$	566	100	%	$	1,046	100	%
										Nine months ended September 30,
											2012				2011
EXPENDITURES FOR PROPERTY PLANT & EQUIPMENT
SDG&E										$	998	44	%	$	1,162	57	%
SoCalGas											462	21			499	25
Sempra South American Utilities											117	5			63	3
Sempra Mexico											13	1			11	1
Sempra Renewables											564	25			124	6
Sempra Natural Gas											84	4			171	8
All other											3	―			1	―
Total										$	2,241	100	%	$	2,031	100	%
										September 30, 2012				December 31, 2011
ASSETS
SDG&E										$	14,589	41	%	$	13,555	41	%
SoCalGas											8,784	25			8,475	25
Sempra South American Utilities											3,241	9			2,981	9
Sempra Mexico											3,042	9			2,914	9
Sempra Renewables											2,412	7			1,210	4
Sempra Natural Gas											5,910	17			5,738	17
All other											520	1			538	2
Intersegment receivables(3)											(3,108)	(9)			(2,162)	(7)
Total										$	35,390	100	%	$	33,249	100	%
INVESTMENTS IN EQUITY METHOD INVESTEES
Sempra Mexico										$	333			$	302
Sempra Renewables											666				390
Sempra Natural Gas											369				800
All other											135				137
Total										$	1,503			$	1,629
(1)	Revenues for reportable segments include intersegment revenues of:
	$3 million, $17 million, $78 million and $73 million for the three months ended September 30, 2012; $6 million, $48 million, $161 million and $144 million for the nine months ended September 30, 2012; $2 million, $13 million, $48 million and $62 million for the three months ended September 30, 2011; and $5 million, $38 million, $157 million and $172 million for the nine months ended September 30, 2011 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.
(2)	After preferred dividends.
(3)	Assets for reportable segments include intersegment receivables of:
	$17 million, $280 million, $54 million, $643 million, $521 million, and $1.6 billion at September 30, 2012; and $67 million, $40 million, $52 million, $543 million, $263 million, and $1.2 billion at December 31, 2011 for SDG&E, SoCalGas, Sempra South American Utilities, Sempra Mexico, Sempra Renewables and Sempra Natural Gas, respectively.

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

You should read the following discussion in conjunction with the financial statements contained in this Form 10-Q; “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in Exhibit 99.4 to Sempra Energy’s Current Report on Form 8-K dated May 11, 2012 (Form 8-K); the Notes to Consolidated Financial Statements contained in Exhibit 99.5 to the Form 8-K; and “Risk Factors” contained in our 2011 Annual Report on Form 10-K (Form 10-K). We refer to the Form 8-K throughout this Form 10-Q as the Updated Annual Report.

OVERVIEW

2012 Business Segment Realignment

Effective January 1, 2012, management realigned some of the company’s major subsidiaries to better fit its strategic direction and to enhance the management and integration of our assets. This realignment resulted in a change in reportable segments in 2012. In accordance with accounting principles generally accepted in the United States (GAAP), we have restated historical information in this Form 10-Q to reflect the effect of this change. All discussions of our operating units and reportable segments in this report reflect the new segments and operating structure.

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

This report includes information for the following separate registrants:

§   Sempra Energy and its consolidated entities

§   SDG&E

§   SoCalGas

References in this report to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by the context. All references in this report 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 3.4 million consumers (1.4 million meters) §Provides natural gas to 3.1 million consumers (855,000 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 million (5.8 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 and Sempra U.S. Gas & Power operating units described below.

We provide descriptions of our reorganized businesses, Sempra International and Sempra U.S. Gas & Power, below.

SEMPRA INTERNATIONAL
	MARKET	GEOGRAPHIC REGION
SEMPRA SOUTH AMERICAN UTILITIES Infrastructure supports electric transmission and distribution	§Provides electricity to more than 600,000 customers in Chile and more than 900,000 customers in Peru	§Serves the cities of Valparaiso and Viña del Mar in central Chile §Serves the southern zone of metropolitan Lima, Peru
SEMPRA MEXICO Develops, owns and operates, or holds interests in: §natural gas transmission pipelines and propane systems §a natural gas distribution utility §electric generation facilities, including wind §a terminal in Mexico for the importation of liquefied natural gas (LNG) and purchase and sale of natural gas	§Natural gas §Wholesale electricity §Liquefied natural gas	§Mexico

Sempra International

Sempra South American Utilities

Sempra South American Utilities operates electric transmission and distribution utilities in Chile and Peru, and owns interests in utilities in Argentina.

On April 6, 2011, Sempra South American Utilities completed the acquisition of AEI’s interests in Chilquinta Energía S.A. (Chilquinta Energía) in Chile and Luz del Sur S.A.A. (Luz del Sur) in Peru. Upon completion of the transaction, Sempra South American Utilities owned 100 percent of Chilquinta Energía and approximately 76 percent of Luz del Sur, and the companies are now consolidated. Pursuant to a tender offer that was completed in September 2011, Sempra South American Utilities now owns 79.82 percent of Luz del Sur, as we discuss in Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report. The remaining shares of Luz del Sur are held by institutional investors and the general public.

We provide additional information about the acquisition and Sempra South American Utilities’ investments in Chilquinta Energía and Luz del Sur in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra South American Utilities also is currently pursuing the sale of its interests in the Argentine utilities, which we discuss further in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Sempra Mexico

Gas Business

Pipelines. Sempra Mexico owns and operates natural gas transmission pipelines and propane systems in Mexico. These facilities are contracted under long-term, U.S. dollar-based agreements with PEMEX (the Mexican state-owned oil company), the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE), Shell México Gas Natural (Shell), Gazprom Marketing & Trading Mexico (Gazprom) and other similar counterparties. Sempra Mexico also owns a 50-percent interest in Gasoductos de Chihuahua, a joint venture with PEMEX which operates two natural gas pipelines and a propane system in northern Mexico.

LNG. Sempra Mexico’s Energía Costa Azul LNG terminal in Baja California, Mexico is capable of processing 1 billion cubic feet (Bcf) of natural gas per day. The Energía Costa Azul facility generates revenue under a capacity services agreement with Shell, expiring in 2028, that originally permitted Shell to use one-half of the terminal’s capacity. In April 2009, Shell assigned a portion of its terminal capacity at Energía Costa Azul to Gazprom, transferring all further rights and obligations with respect to the assigned capacity, and a separate capacity services agreement between Energía Costa Azul and Gazprom was put into place.

A nitrogen-injection facility at Energía Costa Azul allows the terminal to process LNG cargoes from a wider variety of sources and provides additional revenue from payments for capacity reservation and usage fees for nitrogen injection services for Shell and Gazprom.

In connection with Sempra Natural Gas’ LNG purchase agreement with Tangguh PSC Contractors (Tangguh PSC), which we discuss below, Sempra Mexico purchases from Sempra Natural Gas the LNG delivered to Energía Costa Azul by Tangguh PSC. Sempra Mexico uses the natural gas produced from this LNG to supply a contract through 2022 for the sale of an average of approximately 150 million cubic feet per day of natural gas to Mexico’s national electric company, the CFE, at prices that are based on the Southern California border index. If LNG volumes received from Tangguh PSC are not sufficient to satisfy the commitment to the CFE, Sempra Mexico may purchase natural gas from Sempra Natural Gas’ natural gas marketing operations. Under an agreement which expires in the third quarter of 2014 among Sempra Natural Gas, Sempra Mexico, J.P. Morgan Mexico and J.P. Morgan Ventures, Sempra Natural Gas and Sempra Mexico sell to J.P. Morgan Ventures and J.P. Morgan Mexico any volumes received from Tangguh PSC that are not sold to the CFE. The agreement was previously with RBS Sempra Commodities LLP (RBS Sempra Commodities). In connection with the 2010 sale of businesses within RBS Sempra Commodities, substantially all contracts with RBS Sempra Commodities were assigned to J.P. Morgan Ventures by May 1, 2011, as we discuss under “Transactions with RBS Sempra Commodities” in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

Natural Gas Distribution. Sempra Mexico’s natural gas distribution utility, Ecogas Mexico, S de RL de CV (Ecogas), operates in three separate areas in Mexico, and had approximately 90,000 customers and sales volume of 60 million cubic feet per day in 2011.

Power Business

Natural Gas-Fired Generation. Sempra Mexico’s Termoeléctrica de Mexicali, a 625-megawatt (MW) natural gas-fired power plant, is located in Mexicali, Baja California, Mexico. Under an agreement with Sempra Natural Gas, Sempra Mexico records revenue for the sale of power generated by Termoeléctrica de Mexicali to Sempra Natural Gas, and records cost of sales for purchases from Sempra Natural Gas of natural gas to fuel the facility. J.P. Morgan Ventures Energy Corporation (J.P. Morgan Ventures) facilitates the natural gas transactions between the segments.

Wind Power Generation. Sempra Mexico is developing a wind power generation project, Energía Sierra Juárez, in Baja California, Mexico. The project will be developed in phases. In April 2011, SDG&E entered into a 20-year contract for up to 156 MW of renewable power supplied from the first phase of the project, which we expect to be fully operational in 2014.

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: §a natural gas-fired electric generation plant §natural gas pipelines and storage facilities §natural gas distribution utilities §a terminal in the U.S. for the importation and export of LNG and sale of natural gas §marketing operations	§Wholesale electricity §Natural gas §Liquefied natural gas	§U.S.A.

Sempra U.S. Gas & Power

Sempra Renewables

The following table provides information about the Sempra Renewables facilities that were operational as of September 30, 2012. The generating capacity of these facilities is fully contracted under long-term contracts, as we discuss below.

SEMPRA RENEWABLES OPERATING FACILITIES
Capacity in Megawatts (MW) at September 30, 2012
Name		Installed Generating Capacity		First In Service	Location
Cedar Creek 2 Wind Farm (50% owned)		125	(1)	2011	New Raymer, Colorado
Fowler Ridge 2 Wind Farm (50% owned)		100	(1)	2009	Benton County, Indiana
Copper Mountain Solar 1		58	(2)	2010	Boulder City, Nevada
Copper Mountain Solar 2		64	(3)	2012	Boulder City, Nevada
Mesquite Solar 1		42/84	(4)	2011/2012	Arlington, Arizona
	Total MW in operation	473
(1)	Sempra Renewables’ share.
(2)	Includes the 10-MW facility previously referred to as El Dorado Solar, which was first placed in service in 2008.
(3)	Represents only the portion of the project that was completed as of September 30, 2012. The entire 92-MW first phase of Copper Mountain Solar 2 is expected to be placed in service by the end of 2012.
(4)	Represents only the portion of the project that was completed in the year indicated. The entire 150-MW project is expected to be placed in service by December 2012.

We discuss these facilities in more detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Updated Annual Report.

Sempra Natural Gas

Generation. Sempra Natural Gas sells electricity under short-term and long-term contracts and into the spot market and other competitive markets. While it may also purchase electricity in the open market to satisfy its contractual obligations, Sempra Natural Gas generally purchases natural gas to fuel its Mesquite Power natural gas-fired power plant, and, as we discuss above, Sempra Mexico’s Termoeléctrica de Mexicali plant. The Mesquite Power plant is a 1,250-MW facility located in Arlington, Arizona.

Sempra Natural Gas’ El Dorado natural gas-fired generation plant (excluding the solar facility) was sold to SDG&E on October 1, 2011 and was renamed Desert Star. This sale, pursuant to an option to acquire the plant that was exercised by SDG&E in 2007, coincided with the end of a contract with the California Department of Water Resources (DWR). During the first three quarters of 2011, the Mesquite Power plant and the El Dorado generation plant, along with Sempra Mexico’s Termoeléctrica de Mexicali power plant, sold the majority of their output under this long-term purchased-power contract with the DWR, which provided for 1,200 MW to be supplied during all hours and an additional 400 MW during on-peak hours and ended on September 30, 2011.

Sempra Natural Gas also has various power sale transactions intended to hedge its generation capacity. Power has been sold to J.P. Morgan Ventures, generally through 2012. These contracts were initially with RBS Sempra Commodities. In connection with the 2010 sale of businesses within RBS Sempra Commodities, substantially all of these transactions with RBS Sempra Commodities were assigned to J.P. Morgan Ventures by May 1, 2011. In addition, Sempra Natural Gas has power sale transactions for various quantities of power for delivery in 2013 and 2014. Finally, Sempra Natural Gas has sold certain quantities of expected future generation output under long-term contracts. The remaining output of our natural gas-fired generation facilities, including that of Sempra Mexico’s Termoeléctrica de Mexicali power plant, is available to be sold into energy markets on a day-to-day basis.

Transportation and Storage. Sempra Natural Gas owns and operates, or holds interests in, natural gas underground storage and related pipeline facilities in Alabama, Louisiana and Mississippi. Sempra Natural Gas provides natural gas marketing, trading and risk management activities through the utilization and optimization of contracted natural gas supply, transportation and storage capacity, as well as optimizing its assets in the short-term services market.

Sempra Natural Gas, Kinder Morgan Energy Partners, L.P. (KMP) and Phillips 66 jointly own, through Rockies Express Pipeline LLC (Rockies Express), the Rockies Express Pipeline (REX) that links producing areas in the Rocky Mountain region to the upper Midwest and the eastern United States. Our ownership interest in the pipeline is 25 percent. Sempra Rockies Marketing has an agreement through November 2019 with Rockies Express for 200 million cubic feet per day of capacity on REX, which has a total capacity of 1.8 Bcf per day. Sempra Rockies Marketing released a portion of its capacity to RBS Sempra Commodities, which capacity was assigned to J.P. Morgan Ventures effective January 1, 2011 in connection with the sale of businesses within RBS Sempra Commodities. This contract expires December 31, 2013.

In the second and third quarters of 2012, we recorded noncash impairment charges of $179 million and $60 million after-tax, respectively, to write down our investment in the partnership that operates REX. We discuss our investment in Rockies Express and the impairments in Notes 4 and 8 of the Notes to Condensed Consolidated Financial Statements herein.

Distribution.  Sempra Natural Gas owns and operates Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas Company (Willmut Gas), regulated natural gas distribution utilities in southwest Alabama and in Mississippi, respectively. Sempra Natural Gas acquired Willmut Gas in May 2012, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.

LNG.Sempra Natural Gas’ Cameron LNG terminal in Hackberry, Louisiana is capable of processing 1.5 Bcf of natural gas per day. Cameron LNG generates revenue under a capacity services agreement for approximately 600 million cubic feet of natural gas per day through 2029. The agreement allows customers to pay Sempra Natural Gas capacity reservation and usage fees to use its facilities to receive, store and regasify the customer’s LNG. Sempra Natural Gas also may enter into short-term and/or long-term supply agreements to purchase LNG to be received, stored and regasified at its terminals for sale to other parties. Sempra Natural Gas is currently taking steps towards the development of a liquefaction and exportation facility at the Cameron LNG terminal. We discuss these activities below in “Factors Influencing Future Performance.”

Sempra Natural Gas has an LNG purchase agreement with Tangguh PSC for the supply of the equivalent of 500 million cubic feet of natural gas per day from Tangguh PSC’s Indonesian liquefaction facility with delivery to Sempra Mexico’s Energía Costa Azul receipt terminal at a price based on the Southern California border index for natural gas. As discussed above, Sempra Natural Gas has an agreement to sell to J.P. Morgan Ventures any volumes purchased from Tangguh PSC that are not sold to the CFE or J.P. Morgan Mexico. This agreement was previously with RBS Sempra Commodities. In connection with the 2010 sale of businesses within RBS Sempra Commodities, substantially all contracts with RBS Sempra Commodities were assigned to J.P. Morgan Ventures by May 1, 2011. Sempra Natural Gas may also record revenues from non-delivery of cargoes related to this contract.

Sempra Natural Gas also owns property in Port Arthur, Texas, that it is evaluating for potential development.

RBS Sempra Commodities LLP

Prior to 2011, our Sempra Commodities segment contained our investment in RBS Sempra Commodities LLP (RBS Sempra Commodities), which held commodities-marketing businesses previously owned by us. Our investment in the partnership is reported on the equity method. We and The Royal Bank of Scotland plc (RBS), our partner in the joint venture, sold substantially all of the partnership’s businesses and assets in four separate transactions completed in July, November and December of 2010 and February of 2011. We discuss these transactions and other matters concerning the partnership in Notes 4 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

The activity in the partnership no longer meets the quantitative thresholds that require Sempra Commodities to be reported as a reportable segment under applicable accounting rules, and we do not consider the remaining wind-down activities of the partnership to be of continuing significance. As a result, since January 1, 2011, we have reported the former Sempra Commodities segment in Parent and Other.

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 $21 million (7%) to $268 million in the three months ended September 30, 2012, and by $480 million (46%) to $566 million in the nine months ended September 30, 2012.

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

§   lower earnings at Sempra Natural Gas primarily due to the end of the DWR contract in September 2011; and

§   a $60 million noncash impairment charge in 2012 to further write down our investment in Rockies Express; offset by

§   improved results at SDG&E, Sempra Renewables, Sempra Mexico and Parent and Other.

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

§   a $277 million gain resulting from the remeasurement of our equity method investments at our South American Utilities segment related to its acquisition of additional interests in Chilquinta Energía and Luz del Sur in April 2011;

§   a $239 million cumulative noncash impairment charge in 2012 to write down our investment in Rockies Express; and

§   lower earnings at Sempra Natural Gas primarily due to the end of the DWR contract in September 2011; offset by

§   improved results at SDG&E, Sempra Renewables, Sempra Mexico and Parent and Other.

Diluted earnings per share for the three-month period decreased by $0.11 per share to $1.09 per share, while diluted earnings per share for the nine-month period decreased by $2.01 per share to $2.31 per share. The decreases in our diluted earnings per share were primarily due to the factors discussed above.

CHANGE IN ACCOUNTING PRINCIPLE

As we discuss in Note 1 of the Notes to Condensed Consolidated Financial Statements herein, effective January 1, 2012, we changed our method of accounting for investment tax credits (ITC) from the flow-through method to the deferral method. We applied this change in accounting principle by retrospectively adjusting the historical financial statement amounts for all periods presented.  The change in accounting principle has no impact on the financial results of SDG&E or SoCalGas for prior or future periods.

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,
		2012				2011
California Utilities:
SDG&E(1)		$	174	65	%	$	113	39	%
SoCalGas(1)			71	26			81	28
Sempra International:
Sempra South American Utilities			40	15			50	17
Sempra Mexico			54	20			47	16
Sempra U.S. Gas & Power:
Sempra Renewables			13	5			1	1
Sempra Natural Gas			(68)	(25)			41	14
Parent and other(2)			(16)	(6)			(44)	(15)
Earnings		$	268	100	%	$	289	100	%
		Nine months ended September 30,
		2012				2011
California Utilities:
SDG&E(1)		$	374	66	%	$	273	26	%
SoCalGas(1)			190	34			208	20
Sempra International:
Sempra South American Utilities			118	21			386	37
Sempra Mexico			134	24			121	12
Sempra U.S. Gas & Power:
Sempra Renewables			47	8			9	1
Sempra Natural Gas			(260)	(46)			151	14
Parent and other(2)			(37)	(7)			(102)	(10)
Earnings		$	566	100	%	$	1,046	100	%
(1)	After preferred dividends.
(2)	Includes after-tax interest expense ($37 million and $34 million for the three months ended September 30, 2012 and 2011, respectively, and $110 million and $103 million for the nine months ended September 30, 2012 and 2011, 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, unless otherwise noted.

EARNINGS BY SEGMENT – CALIFORNIA UTILITIES

(Dollars in millions)

SDG&E

Our SDG&E segment recorded earnings of:

§   $174 million in the three months ended September 30, 2012 ($176 million before preferred dividends)

§   $113 million in the three months ended September 30, 2011 ($115 million before preferred dividends)

§   $374 million for the first nine months of 2012 ($378 million before preferred dividends)

§   $273 million for the first nine months of 2011 ($277 million before preferred dividends)

The increase of $61 million (54%) in the three months ended September 30, 2012 was primarily due to:

§   $43 million reduction in 2012 income tax expense primarily due to the impact of repairs allowance deductions for 2011 and 2012, as we discuss below in “Income Taxes;”

§   $7 million favorable earnings impact due to the incremental wildfire insurance premiums in 2011 not recovered in revenues until the fourth quarter of 2011;

§   $7 million higher electric transmission margin (excluding Sunrise Powerlink);

§   $6 million lower expense associated with the settlement of 2007 wildfire claims;

§   $5 million higher earnings related to Sunrise Powerlink; and

§   $5 million in earnings for Desert Star in 2012, which was acquired in October 2011; offset by

§   $8 million higher interest expense; and

§   $7 million higher depreciation and operation and maintenance expenses related to California Public Utilities Commission (CPUC)-regulated operations (excluding insurance premiums for wildfire coverage, litigation and Desert Star) with no corresponding increase in the CPUC-authorized margin in 2012 due to the delay in the 2012 General Rate Case (GRC) decision.

The increase of $101 million (37%) in the first nine months of 2012 was primarily due to:

§   $37 million reduction in 2012 income tax expense primarily due to the impact of repairs allowance deductions for 2011 and 2012;

§   $29 million higher earnings related to Sunrise Powerlink;

§   $25 million favorable earnings impact due to the incremental wildfire insurance premiums in 2011 not recovered in revenues until the fourth quarter of 2011;

§   $14 million in earnings for Desert Star in 2012, which was acquired in October 2011;

§   $6 million for the recovery in 2012 of incremental costs incurred in prior years for the long-term storage of spent nuclear fuel;

§   $5 million increase in allowance for funds used during construction (AFUDC) related to equity (excluding Sunrise Powerlink);

§   $4 million higher electric transmission margin (excluding Sunrise Powerlink); and

§   $3 million lower expense associated with the settlement of 2007 wildfire claims; offset by

§   $12 million higher depreciation and operation and maintenance expenses related to CPUC-regulated operations (excluding insurance premiums for wildfire coverage, litigation and Desert Star) with no corresponding increase in the CPUC-authorized margin in 2012 due to the delay in the 2012 GRC decision; and

§   $11 million higher interest expense.

SoCalGas

Our SoCalGas segment recorded earnings of:

§   $71 million in the three months ended September 30, 2012 (both before and after preferred dividends)

§   $81 million in the three months ended September 30, 2011 (both before and after preferred dividends)

§   $190 million for the first nine months of 2012 ($191 million before preferred dividends)

§   $208 million for the first nine months of 2011 ($209 million before preferred dividends)

The decrease of $10 million (12%) in the three months ended September 30, 2012 was primarily due to:

§   $5 million increase in depreciation with no corresponding increase in CPUC-authorized margin in 2012 due to the delay in the 2012 GRC decision;

§   $3 million due to a slightly higher effective tax rate; and

§   $2 million lower regulatory awards.

The decrease of $18 million (9%) in the first nine months of 2012 was primarily due to:

§   $13 million increase in depreciation with no corresponding increase in CPUC-authorized margin in 2012 due to the delay in the 2012 GRC decision; and

§   $8 million higher income tax expense due to a higher effective tax rate; offset by

§   $5 million from an increase in AFUDC related to equity.

EARNINGS BY SEGMENT – SEMPRA INTERNATIONAL

(Dollars in millions)

Sempra South American Utilities

Our Sempra South American Utilities segment recorded earnings of:

§   $40 million in the three months ended September 30, 2012

§   $50 million in the three months ended September 30, 2011

§   $118 million for the first nine months of 2012

§   $386 million for the first nine months of 2011

The decrease of $10 million (20%) in the three months ended September 30, 2012 was primarily due to:

§   $19 million earnings in 2011 from foreign currency rate effect for U.S. dollar monetary position in Chile; offset by

§   $7 million higher earnings from operations in 2012 primarily attributable to an increase in customer base and higher consumption.

The decrease of $268 million in the first nine months of 2012 was primarily due to:

§   a $277 million gain related to the remeasurement of the Chilquinta Energía and Luz del Sur equity method investments in April 2011; and

§   $20 million earnings in 2011 from foreign currency rate effect mainly for U.S. dollar monetary position in Chile; offset by

§   $21 million higher earnings in 2012 due to the acquisition of additional interests in Chilquinta Energía and Luz del Sur in April 2011; and

§   $10 million higher earnings from operations in 2012 primarily attributable to an increase in customer base and higher consumption.

Sempra Mexico

Our Sempra Mexico segment recorded earnings of:

§   $54 million in the three months ended September 30, 2012

§   $47 million in the three months ended September 30, 2011

§   $134 million for the first nine months of 2012

§   $121 million for the first nine months of 2011

The increase of $7 million (15%) in the three months ended September 30, 2012 was primarily due to:

§   $17 million primarily due to a prior year outage at our Mexicali power plant and an increase in equity earnings from our joint venture with PEMEX (the Mexican state-owned oil company); and

§   $9 million positive translation effect on Peso-denominated receivables; offset by

§   $4 million income tax expense in 2012 related to Mexican currency and inflation adjustments compared to $17 million income tax benefit in 2011.

The increase of $13 million (11%) in the first nine months ended September 30, 2012 was primarily due to:

§   $23 million primarily due to a prior year outage at our Mexicali power plant, an increase in equity earnings from our joint venture with PEMEX and lower operating expenses at the Energía Costa Azul receipt terminal; and

§   $9 million positive translation effect on Peso-denominated receivables; offset by

§   $3 million income tax expense in 2012 related to Mexican currency and inflation adjustments compared to $10 million income tax benefit in 2011; and

§   $8 million lower natural gas sales.

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

(Dollars in millions)

Sempra Renewables

Our Sempra Renewables segment recorded earnings of:

§   $13 million in the three months ended September 30, 2012

§   $1 million in the three months ended September 30, 2011

§   $47 million for the first nine months of 2012

§   $9 million for the first nine months of 2011

The increase of $12 million in the three months ended September 30, 2012 was primarily due to:

§   $7 million higher deferred income tax benefits as a result of increased investments in solar and wind generating assets in 2012;

§   $3 million higher earnings attributable to our solar assets; and

§   $2 million higher earnings attributable to our wind assets.

The increase of $38 million in the first nine months of 2012 was primarily due to:

§   $26 million higher deferred income tax benefits as a result of increased investments in solar and wind generating assets in 2012;

§   $8 million higher earnings attributable to our solar assets; and

§   $6 million higher production tax credits from our wind assets.

Sempra Natural Gas

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

§   $(68) million in the three months ended September 30, 2012

§   $41 million in the three months ended September 30, 2011

§   $(260) million for the first nine months of 2012

§   $151 million for the first nine months of 2011

The change in the three months ended September 30, 2012 was primarily due to:

§   a $60 million write-down of our investment in Rockies Express in 2012;

§   $47 million lower earnings from natural gas power plant operations primarily from lower natural gas and power prices, including the impact from the end of the DWR contract as of September 30, 2011; and

§   $14 million lower earnings from LNG primarily due to lower natural gas prices in 2012 compared to the same period of the prior year; offset by

§   $6 million operating losses in 2011 from the El Dorado power plant sold to SDG&E as of October 1, 2011.

The change in the first nine months of 2012 was primarily due to:

§   $239 million cumulative write-down of our investment in Rockies Express in 2012;

§   $169 million lower earnings from natural gas power plant operations primarily from lower natural gas and power prices, including the impact from the end of the DWR contract as of September 30, 2011;

§   $20 million lower earnings from LNG primarily due to lower natural gas prices; and

§   $6 million lower earnings primarily from the timing of natural gas inventory withdrawals and an increase in pipeline and storage demand charges related to an increase in natural gas inventory levels; offset by

§   $23 million operating losses in 2011 from the El Dorado power plant sold to SDG&E as of October 1, 2011.

Parent and Other

Losses for Parent and Other were

§   $16 million in the three months ended September 30, 2012

§   $44 million in the three months ended September 30, 2011

§   $37 million for the first nine months of 2012

§   $102 million for the first nine months of 2011

The decrease in losses of $28 million (64%) in the three months ended September 30, 2012 was primarily due to:

§   $15 million higher investment gains on dedicated assets in support of our executive retirement and deferred compensation plans, net of the increase in deferred compensation liability associated with the investments;

§   $10 million write-down of our investment in the RBS Sempra Commodities joint venture in 2011; and

§   $7 million higher earnings from foreign currency exchange effects mainly related to a Chilean holding company; offset by

§   $6 million lower income tax benefits, net of the effects of a Mexican peso income tax hedge.

The decrease in losses of $65 million (64%) in the first nine months of 2012 was primarily due to:

§   $54 million income tax benefit primarily associated with the decision to hold life insurance contracts to term, as we discuss below in “Income Taxes;”

§   $15 million equity losses in 2011 from the RBS Sempra Commodities joint venture, including the $10 million write-down of the investment; and

§   $12 million higher investment gains on dedicated assets in support of our executive retirement and deferred compensation plans, net of the increase in deferred compensation liability associated with the investments;

§   $8 million higher earnings from foreign currency exchange effects mainly related to a Chilean holding company; offset by

§   $25 million lower income tax benefits, net of the effects of a Mexican peso income tax hedge and excluding the $54 million income tax benefit discussed above.

CHANGES IN REVENUES, COSTS AND EARNINGS

This section contains a discussion of the differences between periods in 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 Natural Gas’ Mobile Gas and Willmut Gas, regulated natural gas distribution utilities

§   Sempra Mexico’s Ecogas

Electric revenues at:

§   SDG&E

§   Sempra South American Utilities’ Chilquinta Energía and 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 on to customers substantially as incurred. However, SoCalGas’ Gas Cost Incentive Mechanism provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in Note 9 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,
		2012		2011		2012		2011
Electric revenues:
SDG&E		$	998	$	763	$	2,349	$	2,011
Sempra South American Utilities			335		335		997		659
Eliminations and adjustments			(1)		(2)		(5)		(5)
	Total		1,332		1,096		3,341		2,665
Natural gas revenues:
SoCalGas			728		844		2,328		2,776
SDG&E			94		105		357		394
Sempra Mexico			17		20		55		70
Sempra Natural Gas			17		14		67		67
Eliminations and adjustments			(18)		(14)		(49)		(39)
	Total		838		969		2,758		3,268
Total utilities revenues		$	2,170	$	2,065	$	6,099	$	5,933
Cost of electric fuel and purchased power:
SDG&E		$	301	$	207	$	604	$	534
Sempra South American Utilities			212		201		647		442
Eliminations and adjustments			2		―		1		―
	Total	$	515	$	408	$	1,252	$	976
Cost of natural gas:
SoCalGas		$	175	$	267	$	703	$	1,133
SDG&E			29		40		130		175
Sempra Mexico			10		15		32		49
Sempra Natural Gas			4		5		16		23
Eliminations and adjustments			(6)		(5)		(17)		(13)
	Total	$	212	$	322	$	864	$	1,367

Sempra Energy Consolidated

Electric Revenues

During the three months ended September 30, 2012, our electric revenues increased by $236 million (22%) to $1.3 billion primarily due to:

§   $235 million increase at SDG&E, which we discuss below; and

§   $31 million increase at Luz del Sur primarily due to higher commodity prices and volume; offset by

§   $31 million decrease at Chilquinta Energía mainly due to lower commodity prices.

Our utilities’ cost of electric fuel and purchased power increased by $107 million (26%) to $515 million in the three months ended September 30, 2012 primarily due to:

§   $94 million increase at SDG&E, which we discuss below; and

§   $11 million increase at our South American utilities due to higher commodity prices and volume at Luz del Sur, offset by lower commodity prices at Chilquinta Energía.

During the nine months ended September 30, 2012, our electric revenues increased by $676 million (25%) to $3.3 billion primarily due to:

§   $338 million increase at our South American utilities, primarily from the consolidation of Chilquinta Energía and Luz del Sur acquired in April 2011. In addition, during the second and third quarters of 2012, electric revenues increased due to higher commodity prices and volume at Luz del Sur, offset by lower commodity prices at Chilquinta Energía; and

§   $338 million increase at SDG&E, which we discuss below.

Our utilities’ cost of electric fuel and purchased power increased by $276 million (28%) to $1.3 billion in the nine months ended September 30, 2012 primarily due to:

§   $205 million increase at Chilquinta Energía and Luz del Sur associated with the higher revenues; and

§   $70 million increase at SDG&E, which we discuss below.

Natural Gas Revenues

During the three months ended September 30, 2012, Sempra Energy’s natural gas revenues decreased by $131 million (14%) to $838 million, and the cost of natural gas decreased by $110 million (34%) to $212 million. The decrease in natural gas revenues included $116 million at SoCalGas and $11 million at SDG&E, primarily due to decreases in commodity costs in 2012.

During the nine months ended September 30, 2012, Sempra Energy’s natural gas revenues decreased by $510 million (16%) to $2.8 billion, and the cost of natural gas decreased by $503 million (37%) to $864 million. The decrease in natural gas revenues included $448 million at SoCalGas and $37 million at SDG&E.

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-month periods ended September 30, 2012 and 2011. Because the cost of electricity is substantially recovered in rates, changes in the cost are reflected in the changes in revenues.

SDG&E
ELECTRIC DISTRIBUTION AND TRANSMISSION
(Volumes in millions of kilowatt-hours, dollars in millions)
		Nine months ended September 30, 2012			Nine months ended September 30, 2011
Customer class		Volumes	Revenue		Volumes	Revenue
Residential		5,650	$	907	5,552	$	916
Commercial		5,157		753	5,068		760
Industrial		1,529		184	1,525		187
Direct access		2,473		110	2,427		109
Street and highway lighting		70		9	76		11
		14,879		1,963	14,648		1,983
Other revenues				125			84
Balancing accounts				261			(56)
Total(1)			$	2,349		$	2,011
(1)	Includes sales to affiliates of $5 million in both 2012 and 2011.

During the three months ended September 30, 2012, electric revenues increased by $235 million (31%) to $998 million at SDG&E, primarily due to:

§   an increase in cost of electric fuel and purchased power in 2012;

§   $62 million higher authorized revenues from electric transmission;

§   $44 million higher recoverable expenses that are fully offset in operation and maintenance expenses;

§   $35 million higher authorized revenues from electric generation, primarily due to the acquisition of the Desert Star generation facility in October 2011; and

§   $15 million revenues associated with incremental wildfire insurance premiums.

SDG&E’s cost of electric fuel and purchased power increased by $94 million (45%) to $301 million in the three months ended September 30, 2012 primarily due to the cost of power generated and purchased to replace the loss of SONGS-produced power.

During the nine months ended September 30, 2012, electric revenues increased by $338 million (17%) to $2.3 billion at SDG&E, primarily due to:

§   an increase in cost of electric fuel and purchased power in 2012;

§   $94 million higher authorized revenues from electric generation, primarily due to the acquisition of the Desert Star generation facility in October 2011;

§   $69 million higher authorized revenues from electric transmission;

§   $67 million higher recoverable expenses that are fully offset in operation and maintenance expenses; and

§   $47 million revenues associated with incremental wildfire insurance premiums.

SDG&E’s cost of electric fuel and purchased power increased by $70 million (13%) to $604 million in the nine months ended September 30, 2012 primarily due to the cost of power generated and purchased to replace the loss of SONGS-produced power.

We do not include in the Condensed Consolidated Statements of Operations the commodity costs (and the revenues to recover those costs) associated with long-term contracts that are allocated to SDG&E by the California DWR. However, we do include the associated volumes and distribution revenues in the table above. We provide further discussion of these contracts in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

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-month periods ended September 30, 2012 and 2011. 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 Updated 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, 2012:
Residential		24	$	210	―	$	1	24	$	211
Commercial and industrial		11		58	7		7	18		65
Electric generation plants		―		―	26		7	26		7
		35	$	268	33	$	15	68		283
Other revenues										30
Balancing accounts										44
Total(1)									$	357
Nine months ended September 30, 2011:
Residential		24	$	261	―	$	―	24	$	261
Commercial and industrial		11		80	6		7	17		87
Electric generation plants		―		―	20		6	20		6
		35	$	341	26	$	13	61		354
Other revenues										26
Balancing accounts										14
Total(1)									$	394
(1)	Includes sales to affiliates of $1 million in both 2012 and 2011.

During the three months ended September 30, 2012, SDG&E’s natural gas revenues decreased by $11 million (10%) to $94 million, and the cost of natural gas sold decreased by $11 million (28%) to $29 million. During the nine months ended September 30, 2012, SDG&E’s natural gas revenues decreased by $37 million (9%) to $357 million, and the cost of natural gas decreased by $45 million (26%) to $130 million.

SDG&E’s average cost of natural gas for the three months ended September 30, 2012 was $3.90 per thousand cubic feet (Mcf) compared to $5.30 per Mcf for the corresponding period in 2011, a 26-percent decrease of $1.40 per Mcf, resulting in lower revenues and cost of $10 million. For the first nine months of 2012, SDG&E’s average cost of natural gas was $3.66 per Mcf compared to $4.96 per Mcf for the corresponding period in 2011, a 26-percent decrease of $1.30 per Mcf, resulting in lower revenues and cost of $46 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, 2012:
Residential		168	$	1,382	1	$	6	169	$	1,388
Commercial and industrial		75		438	212		181	287		619
Electric generation plants		―		―	180		34	180		34
Wholesale		―		―	129		18	129		18
		243	$	1,820	522	$	239	765		2,059
Other revenues										74
Balancing accounts										195
Total(1)									$	2,328
Nine months ended September 30, 2011:
Residential		175	$	1,678	1	$	2	176	$	1,680
Commercial and industrial		75		566	204		163	279		729
Electric generation plants		―		―	127		35	127		35
Wholesale		―		―	107		14	107		14
		250	$	2,244	439	$	214	689		2,458
Other revenues										71
Balancing accounts										247
Total(1)									$	2,776
(1)	Includes sales to affiliates of $48 million in 2012 and $38 million in 2011.

During the three months ended September 30, 2012, SoCalGas’ natural gas revenues decreased by $116 million (14%) to $728 million, and the cost of natural gas sold decreased by $92 million (34%) to $175 million. During the nine months ended September 30, 2012, SoCalGas’ natural gas revenues decreased by $448 million (16%) to $2.3 billion, and the cost of natural gas sold decreased by $430 million (38%) to $703 million.

SoCalGas’ average cost of natural gas for the three months ended September 30, 2012 was $3.26 per Mcf compared to $4.80 per Mcf for the corresponding period in 2011, a 32-percent decrease of $1.54 per Mcf, resulting in lower revenues and cost of $83 million.

For the first nine months of 2012, SoCalGas’ average cost of natural gas was $2.90 per Mcf compared to $4.53 per Mcf for the corresponding period in 2011, a 36-percent decrease of $1.63 per Mcf, resulting in lower revenues and cost of $394 million. The decrease in the cost of natural gas sold was also attributable to lower demand for natural gas from a warmer winter in 2012.

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 basis for the tariffs do not meet the requirement necessary for treatment under GAAP for regulatory accounting. We discuss revenue recognition further for Chilquinta Energía and Luz del Sur in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Operations of Mobile Gas, Willmut Gas and Ecogas qualify for regulatory accounting treatment under applicable GAAP, similar to the California Utilities.

The table below summarizes natural gas and electric revenues for our other utilities for the nine months ended September 30, 2012 and 2011:

OTHER UTILITIES
NATURAL GAS AND ELECTRIC REVENUES
(Dollars in millions)
		Nine months ended September 30, 2012			Nine months ended September 30, 2011
		Volumes	Revenue		Volumes	Revenue
Natural Gas Sales (billion cubic feet):
Sempra Natural Gas:
	Mobile Gas	30	$	62	29	$	67
	Willmut Gas(1)	8		5	―		―
Sempra Mexico - Ecogas		17		55	16		70
	Total	55	$	122	45	$	137
Electric Sales (million kilowatt hours)(2):
Sempra South American Utilities:
	Luz del Sur	4,996	$	563	3,118	$	317
	Chilquinta Energía	2,015		393	1,201		315
		7,011		956	4,319		632
Other service revenues				41			27
	Total		$	997		$	659
(1)	We acquired Willmut Gas in May 2012.
(2)	We accounted for Luz del Sur and Chilquinta Energía under the equity method until April 6, 2011, when they became consolidated entities upon our acquisition of additional ownership interests.

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,
		2012		2011		2012		2011
Energy-related businesses revenues:
Sempra South American Utilities		$	21	$	10	$	64	$	47
Sempra Mexico			164		163		379		491
Sempra Renewables			27		7		49		17
Sempra Natural Gas			277		441		694		1,273
Intersegment revenues, adjustments and eliminations(1)			(152)		(110)		(306)		(329)
Total energy-related businesses revenues		$	337	$	511	$	880	$	1,499
Cost of natural gas, electric fuel and purchased power(2):
Sempra Mexico		$	72	$	82	$	145	$	253
Sempra Renewables			2		―		2		―
Sempra Natural Gas			215		283		504		774
Adjustments and eliminations(1)			(153)		(113)		(305)		(333)
Total cost of natural gas, electric fuel
and purchased power		$	136	$	252	$	346	$	694
Other cost of sales(2):
Sempra South American Utilities		$	20	$	45	$	48	$	54
Sempra Mexico			1		1		3		3
Sempra Natural Gas			22		23		66		66
Adjustments and eliminations(1)			―		(1)		―		―
Total other cost of sales		$	43	$	68	$	117	$	123
(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, 2012, revenues from our energy-related businesses decreased by $174 million (34%) to $337 million. The decrease included

§   $164 million decrease at Sempra Natural Gas due to decreased power sales primarily from the end of the DWR contract as of September 30, 2011. Part of the decrease was offset by higher merchant sales in 2012; and

§   $42 million higher intercompany eliminations primarily associated with sales between Sempra Mexico and Sempra Natural Gas; offset by

§   $20 million increase at Sempra Renewables mainly from revenues generated by our solar assets.

During the three months ended September 30, 2012, the cost of natural gas, electric fuel and purchased power for our energy-related businesses decreased by $116 million (46%) to $136 million. The decrease was primarily due to:

§   $68 million decrease at Sempra Natural Gas primarily associated with the lower revenues; and

§   $40 million higher intercompany eliminations primarily associated with sales between Sempra Mexico and Sempra Natural Gas.

During the nine months ended September 30, 2012, revenues from our energy-related businesses decreased by $619 million (41%) to $880 million. The decrease included

§   $579 million decrease at Sempra Natural Gas due to decreased power sales primarily from the end of the DWR contract, and lower natural gas revenues from its LNG operations as a result of lower natural gas prices and volumes. Part of the decrease was offset by higher merchant sales in 2012; and

§   $112 million decrease at Sempra Mexico mainly from lower natural gas prices and lower LNG volumes sold; offset by

§   $32 million increase at Sempra Renewables mainly from revenues generated by our solar assets; and

§   $23 million lower intercompany eliminations primarily associated with sales between Sempra Mexico and Sempra Natural Gas.

During the nine months ended September 30, 2012, the cost of natural gas, electric fuel and purchased power for our energy-related businesses decreased by $348 million (50%) to $346 million. The decrease was primarily due to:

§   $270 million decrease at Sempra Natural Gas primarily associated with the lower revenues; and

§   $108 million decrease at Sempra Mexico associated with the lower revenues; offset by

§   $28 million lower intercompany eliminations primarily associated with sales between Sempra Mexico and Sempra Natural Gas.

Operation and Maintenance

Sempra Energy Consolidated

For the three months ended September 30, 2012, our operation and maintenance expenses increased by $41 million (6%) to $732 million primarily due to:

§   $54 million increase at SDG&E, which we discuss below; offset by

§   $15 million decrease at SoCalGas, primarily due to lower recoverable expenses in 2012.

For the nine months ended September 30, 2012, our operation and maintenance expenses increased by $120 million (6%) to $2.1 billion. The increase included

§   $96 million increase at SDG&E, which we discuss below; and

§   $57 million increase at Sempra South American Utilities primarily from the consolidation of expenses in Chile and Peru; offset by

§   $15 million decrease at Parent and Other, mainly due to lower general and administrative costs, including amounts in 2011 related to the dissolution of our former commodities-marketing businesses; and

§   $13 million decrease at SoCalGas, primarily due to $34 million lower recoverable expenses, offset by $20 million higher other operation and maintenance costs.

SDG&E

For the three months ended September 30, 2012, SDG&E’s operation and maintenance expenses increased by $54 million (21%) to $309 million. The increase was primarily due to:

§   $43 million higher recoverable expenses primarily due to an increase in transmission-related operating expenses;

§   $18 million higher other operation and maintenance costs, including

o   $5 million associated with the Desert Star generation facility acquired by SDG&E in October 2011, and

o   $4 million increase in liability insurance premiums for wildfire coverage; and

§   $3 million higher operation and maintenance expenses at Otay Mesa VIE; offset by

§   $10 million lower litigation expenses from wildfire claims.

For the nine months ended September 30, 2012, SDG&E’s operation and maintenance expenses increased by $96 million (13%) to $852 million. The increase was due to:

§   $69 million higher recoverable expenses primarily due to an increase in transmission-related operating expenses; and

§   $40 million higher other operation and maintenance costs, including

o   $21 million associated with the Desert Star generation facility acquired by SDG&E in October 2011 and from increased costs from the operations of other electric generating facilities,

o   $10 million of costs associated with the continued roll-out of the advanced meters, and

o   $5 million increase in liability insurance premiums for wildfire coverage, offset by

o   $10 million recovery in 2012 of incremental costs incurred in prior years for the long-term storage of spent nuclear fuel; offset by

§   $8 million lower operation and maintenance expenses at Otay Mesa VIE; and

§   $5 million lower litigation expenses from wildfire claims.

Equity (Losses) Earnings, Before Income Tax

Equity losses from our investment in Rockies Express were $87 million and $366 million in the three months and nine months ended September 30, 2012, respectively, compared to equity earnings of $10 million and $29 million in the three months and nine months ended September 30, 2011, respectively. Equity losses in the three months and nine months ended September 30, 2012 included write-downs of our investment in Rockies Express of $100 million and $400 million, respectively.

Equity losses before income taxes from our other investments decreased by $15 million and $24 million in the three months and nine months ended September 30, 2012, respectively, primarily due to a $16 million pretax write-down in the third quarter of 2011 of our investment in RBS Sempra Commodities.

Other Income, Net

Sempra Energy Consolidated

In the three months ended September 30, 2012, other income, net, increased by $32 million to $44 million primarily due to:

§   $17 million gains from investment activity related to our executive retirement and deferred compensation plans in 2012 compared to $6 million losses in 2011; and

§   $26 million losses on interest rate and foreign exchange instruments in 2011; offset by

§   $13 million decrease in AFUDC primarily due to completion of construction on the Sunrise Powerlink project in June 2012 at SDG&E.

In the nine months ended September 30, 2012, other income, net, increased by $51 million (59%) to $137 million primarily due to:

§   $11 million gains on interest rate and foreign exchange instruments in 2012 compared to $14 million losses in 2011;

§   $14 million higher gains from investment activity related to our executive retirement and deferred compensation plans in 2012; and

§   $13 million increase in AFUDC at the California Utilities, including $7 million increase at SDG&E due to construction on the Sunrise Powerlink project.

SDG&E

In the three months ended September 30, 2012, other income, net, decreased by $21 million (81%) to $5 million mainly due to a decrease in AFUDC related to equity primarily due to completion of construction on the Sunrise Powerlink project in June 2012. In the nine months ended September 30, 2012, other income, net, increased by $4 million (7%) to $59 million primarily due to an increase in AFUDC related to equity from construction on the Sunrise Powerlink project.

Income Taxes

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

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
		Three months ended September 30,
		2012				2011
			Effective				Effective
		Income Tax	Income			Income Tax	Income
		Expense	Tax Rate			Expense	Tax Rate
Sempra Energy Consolidated	$	49	15	%	$	75	19	%
SDG&E		38	17			63	32
SoCalGas		37	34			41	34
		Nine months ended September 30,
		2012				2011
			Effective				Effective
		Income Tax	Income			Income Tax	Income
		Expense	Tax Rate			Expense	Tax Rate
Sempra Energy Consolidated	$	48	8	%	$	289	22	%
SDG&E		151	27			154	35
SoCalGas		105	35			106	34

Sempra Energy Consolidated

The decrease in income tax expense in the three months ended September 30, 2012 was due to lower pretax income and a lower effective income tax rate. The lower effective income tax rate in the three months ended September 30, 2012 was primarily due to:

§   $38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012. The change in income tax treatment was made pursuant to an Internal Revenue Service Revenue Procedure allowing certain capitalized repair costs for electric transmission and distribution assets to be deducted from taxable income when incurred for tax years beginning on or after January 1, 2011; and

§   higher planned renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; offset by

§   higher income tax expense in 2012 due to Mexican currency translation and inflation adjustments; and

§   higher income tax expense due to unfavorable resolution of prior years’ income tax items.

In the nine months ended September 30, 2012, Sempra Energy’s income tax expense decreased due to significantly lower pretax income (due to the write-down of our investment in Rockies Express in 2012 and the remeasurement gain in 2011 related to our acquisition of controlling interests in Chilquinta Energía and Luz del Sur) and a lower effective income tax rate. The lower effective income tax rate was primarily due to:

§   $54 million income tax benefit primarily associated with our decision to hold life insurance contracts kept in support of certain benefit plans to term. Previously, we took the position that we might cash in or sell these contracts before maturity, which required that we record deferred income taxes on unrealized gains on investments held within the insurance contracts;

§   $38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012, as discussed above; and

§   higher planned renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; offset by

§   lower income in 2012 in countries with lower statutory income tax rates; such income was higher in 2011 due to the $277 million non-taxable gain discussed above;

§   higher income tax expense in 2012 due to Mexican currency translation and inflation adjustments;

§   higher income tax expense due to unfavorable resolution of prior years’ income tax items; and

§   higher U.S. income tax on non-U.S. non-operating activity due to the expiration of the look-through rule, as we discuss below.

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. We also discuss renewable energy income tax credits and deferred income tax benefits related to renewable energy projects in Notes 1 and 5 of the Notes to Condensed Consolidated Financial Statements herein.

As discussed above under “Change in Accounting Principle,” through December 31, 2011, Sempra Renewables used what is referred to as the flow-through method of accounting in which the investment tax credits associated with a project are recognized as a reduction of tax expense in the year in which capacity is placed in service. Starting in the first quarter of 2012, Sempra Renewables adopted the deferral method of accounting for these projects. Under this methodology, instead of recognizing the investment tax credit, Sempra Renewables reduced the book basis of the asset by the amount of the tax credit. This resulted in lower book depreciation, but higher income tax expense. Therefore, over time total earnings will be equal under the deferred method when compared to the flow-through method. This change in accounting principle was applied retrospectively in the first quarter of 2012.

We have used grant accounting for certain assets placed into service in 2012, including assets that were under construction in 2011, in anticipation of applying for cash grants. Grant accounting for cash grants is very similar to the deferral method of accounting for investment tax credits, the primary difference being the recording of a grant receivable instead of an income tax receivable.

In 2012, we anticipate that our effective income tax rate will be approximately 26% compared to 30% in 2011, excluding income tax and pretax items that cannot be reliably forecasted, as discussed in Note 5 of the Notes to Condensed Consolidated Financial Statements herein. This decrease is primarily as a result of higher planned renewable income tax credits, higher deferred income tax benefits related to renewable energy projects, and higher income tax benefits due to the change for income tax purposes allowing certain capitalized utility plant fixed asset repairs to be deducted from taxable income when incurred; offset by decreased favorable income tax deductions for self-developed software costs and higher U.S. income tax on non-U.S. non-operating activity due to the expiration of the look-through rule, as we discuss below.

In the years 2013 through 2016, we are currently projecting that our effective income tax rate will be, excluding income tax items that cannot be reliably forecasted, approximately 30% to 32%. This increase in effective income tax rates is primarily due to projected increases in pretax income, decreases in favorable income tax deductions for self-developed software costs, increases in the amount by which book depreciation exceeds normalized tax depreciation, and lower exclusions from income for the equity portion of AFUDC.

The projected effective tax rates above do not include any impact from a possible repatriation of future earnings from our Mexican and Peruvian subsidiaries. If we were to repatriate future non-U.S. earnings, as we discuss below, the rates would increase accordingly.

SDG&E

SDG&E’s income tax expense decreased in the three months ended September 30, 2012 primarily due to a lower effective income tax rate. The lower effective tax rate was primarily due to:

§   $38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012.  The change in income tax treatment was made pursuant to an Internal Revenue Service Revenue Procedure allowing certain capitalized repair costs for electric transmission and distribution assets to be deducted from taxable income when incurred for tax years beginning on or after January 1, 2011; and

§   higher favorable resolutions of prior years' income tax items; offset by

§   the impact of Otay Mesa VIE, as we discuss below; and

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

SDG&E’s income tax expense decreased in the nine months ended September 30, 2012 when compared to the same period in 2011 primarily due to a lower effective income tax rate. The lower effective tax rate was primarily due to:

§   $38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012, as discussed above;

§   the impact of Otay Mesa VIE, as we discuss below;

§   lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and

§   higher favorable resolutions of prior years’ income tax items; offset by

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

Results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is consolidated, and therefore, their effective income tax rates are impacted by the VIE’s stand-alone effective income tax rate.

In 2012, we anticipate that SDG&E’s effective income tax rate will be approximately 33% compared to 34% in 2011, excluding income tax and pretax items that cannot be reliably forecasted. This decrease is due to higher income tax benefits due to a change for income tax purposes allowing certain capitalized utility plant fixed asset repairs to be deducted from taxable income when incurred; and lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; offset by a projected rise in pretax income, combined with lower exclusions from income for the equity portion of AFUDC (due to the completion of construction on the Sunrise Powerlink electric transmission line). In the years 2013 through 2016, we are currently projecting that SDG&E’s effective income tax rate will be approximately 37%, excluding income tax items that cannot be reliably forecasted, due to projected increases in pretax income.

SoCalGas

SoCalGas’ income tax expense decreased in the three months ended September 30, 2012 primarily due to lower pretax income. While the effective tax rate for 2012 did not change significantly from 2011, it was impacted by:

§   lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and

§   higher exclusions from taxable income of the equity portion of AFUDC; offset by

§   lower deductions for cost of removal of utility plant fixed assets.

In the nine months ended September 30, 2012, income tax expense decreased at SoCalGas primarily due to lower pretax income, offset by a higher effective income tax rate. The higher effective tax rate was primarily due to:

§   lower deductions for self-developed software costs; offset by

§   lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and

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

In 2012, we anticipate that SoCalGas’ effective income tax rate will be approximately 35% compared to 33% in 2011, excluding income tax and pretax items that cannot be reliably forecasted. This increase is due to a projected rise in pretax income, combined with a decrease in favorable income tax deductions for self-developed software costs, offset by lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets. In the years 2013 through 2016, we are currently projecting that SoCalGas’ effective income tax rate, excluding income tax items that cannot be reliably forecasted, will be approximately 40% to 42%. This expected increase is primarily due to projected increases in pretax income, combined with a decrease in favorable income tax deductions for self-developed software costs, and an increase in the amount by which book depreciation exceeds normalized tax depreciation. 

In general, the following items are subject to flow-through treatment at the California Utilities:

§   repairs to a certain portion of utility plant fixed assets

§   the equity portion of AFUDC

§   cost of removal of utility plant assets

§   self-developed software costs

§   depreciation on a certain portion of utility plant fixed assets

We discuss the impact of items subject to flow-through treatment on our effective income tax rates in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.

In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Act) was signed into law. The 2010 Tax Act included the extension of bonus depreciation for U.S. federal income tax purposes for years 2010 through 2012 and an increase in the rate of bonus depreciation from 50 percent to 100 percent. This increased rate only applies to certain investments made after September 8, 2010 through December 31, 2012. Self-constructed property, where the construction period exceeds one year, construction starts between December 31, 2007 and January 1, 2013, and the property is placed in service by December 31, 2013, will qualify for bonus depreciation in 2013 at either the original or increased rate.

Due to the extension of bonus depreciation, Sempra Energy generated a large U.S. federal NOL in 2011 and is currently projecting a large U.S. federal NOL in 2012. We currently project that the total NOL will not be fully utilized until approximately 2016. Because of these projected NOLs, and the carryforward of U.S. federal income tax credits discussed below, Sempra Energy expects no U.S. federal income tax payments in years 2012 through 2015. However, because bonus depreciation only creates a temporary difference, versus a permanent difference, between Sempra Energy’s U.S. federal income tax return and its U.S. GAAP financial statements, it does not impact Sempra Energy’s effective income tax rate. We expect larger U.S. federal income tax payments in the future as these temporary differences reverse.

SDG&E and SoCalGas both generated a large U.S. federal NOL in 2011, also due to bonus depreciation. In 2012, SoCalGas will be able to, on a stand-alone basis, carry back its 2011 NOL to 2009 and 2010 to offset taxable income in those years. Therefore, SoCalGas’ 2011 NOL is recorded as current income tax receivable. SDG&E will be able to, on a stand-alone basis, carry back a majority of its 2011 NOL to 2009 and 2010 to offset taxable income in those years, which portion is recorded as current income tax receivable. The remaining portion of SDG&E’s 2011 NOL is recorded as a deferred income tax asset.

SDG&E is currently projecting a large U.S. federal NOL in 2012. However, SoCalGas is not projecting a U.S. federal NOL in 2012. SDG&E’s 2012 NOL is currently projected to be carried forward, and is therefore recorded as a deferred income tax asset. We currently project that SDG&E’s carryforward NOL, on a stand-alone basis, will be fully utilized by 2014. Because of this projected 2012 NOL, and the carryforward of U.S. federal income tax credits discussed below, SDG&E expects no U.S. federal income tax payments in 2012. However, because bonus depreciation only creates a temporary difference between SDG&E’s and SoCalGas’ U.S. federal income tax returns and U.S. GAAP financial statements, it does not impact SDG&E’s and SoCalGas’ effective income tax rates. We expect larger U.S. federal income tax payments in the future as these temporary differences reverse.

Bonus depreciation, in addition to impacting Sempra Energy’s and SDG&E’s U.S. federal income tax payments, will also have a temporary impact on Sempra Energy’s and SDG&E’s ability to utilize their U.S. federal income tax credits, which primarily are investment tax credits and production tax credits generated by Sempra Energy’s and SDG&E’s current and future renewable energy investments. However, based on current projections, Sempra Energy and SDG&E do not expect, based on more-likely-than-not criteria required under U.S. GAAP, any of these income tax credits to expire prior to the end of their 20-year carryforward period, as allowed under current U.S. federal income tax law. We also expect bonus depreciation to increase the deferred tax component of SDG&E’s and SoCalGas’ rate base, which reduces rate base.

We are currently considering the potential repatriation of future earnings beginning in 2013 from certain of our non-U.S. subsidiaries in Mexico and Peru. However, we expect to continue to indefinitely reinvest future earnings from our Chilean subsidiaries. Currently, all future repatriated earnings would be subject to U.S. income tax (with a credit for foreign income taxes), and future repatriations from Peru would be subject to local country withholding tax. Because this potential repatriation would only be from future earnings, it does not change our current assertion, as we discuss in Note 7 of the Notes to Consolidated Financial Statements in the Updated Annual Report, that we intend to continue to indefinitely reinvest, for the foreseeable future, our cumulative undistributed non-U.S. earnings as of September 30, 2012. The forward-looking statements above on income tax matters do not include any impact from potential repatriation of future non-U.S. earnings.

Additionally, the 2010 Tax Act extended for years 2010 and 2011 the U.S. federal income tax law known as the look-through rule. This rule allows, under certain situations, for certain non-operating activity (e.g., dividend income, royalty income, interest income, rental income, etc.), of a greater than 50-percent owned non-U.S. subsidiary, to not be taxed under U.S. federal income tax law. As of September 30, 2012, this rule has not yet been extended beyond 2011, therefore, Sempra Energy’s effective income tax rate is currently unfavorably impacted for 2012 and could potentially increase, over the amounts projected above, in subsequent years. However, for years 2013-2016, we currently do not believe the lack of the extension of this rule will cause the effective income tax rate to be outside the estimated range provided above. It is generally thought that this rule will be extended beyond 2011. However, until the extension of the rule is enacted into law, U.S. GAAP accounting rules preclude us from reflecting its favorable impact in our financial results for 2012. If, starting in 2013, we were to repatriate future earnings from Mexico and Peru, as discussed above, the loss of the look-through rule will not result in additional U.S. federal income tax.

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

Our Mexican subsidiaries have U.S. dollar denominated 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 expose us to significant fluctuations in our income tax expense.  The income tax expense of Sempra Mexico is impacted by these factors. Parent and Other is also impacted due to a Mexican holding company. The impacts of these fluctuations may offset to some extent at the consolidated level.

For Sempra Energy Consolidated, the impacts on the three months and nine months ended September 30, 2012 and 2011 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 September 30,				Nine months ended September 30,
		2012		2011		2012		2011
Income tax (expense) benefit on currency exchange
	rate movement of monetary assets and liabilities	$	(5)	$	14	$	(7)	$	8
Translation of non-U.S. deferred income tax balances			(7)		17		(7)		10
Income tax expense on inflation			(1)		(1)		(2)		(1)
	Total impact on income taxes		(13)		30		(16)		17
After-tax (losses) gains on Mexican peso exchange rate
	instruments (included in Other Income, Net)		―		(16)		6		(9)
Net impacts on Sempra Energy Condensed
	Consolidated Statements of Operations	$	(13)	$	14	$	(10)	$	8

Equity Earnings, Net of Income Tax

In the nine months ended September 30, 2012, equity earnings of unconsolidated subsidiaries, net of income tax, were $29 million compared to $45 million for the corresponding period in 2011. The change in the nine months ended September 30, 2012 was primarily due to lower earnings related to equity method investments in Chile and Peru, for entities that are now consolidated, offset by higher earnings from Sempra Mexico’s pipeline assets.

Earnings Attributable to Noncontrolling Interests

Sempra Energy Consolidated

Earnings attributable to noncontrolling interests decreased by $9 million for the three months ended September 30, 2012 due to lower earnings attributable to the noncontrolling interest at Otay Mesa VIE.

Earnings attributable to noncontrolling interests increased by $23 million for the nine months ended September 30, 2012 primarily due to:

§   $17 million higher earnings attributable to noncontrolling interest in 2012 at Otay Mesa VIE; and

§   $4 million higher earnings at Sempra South American Utilities primarily from noncontrolling interests at Luz del Sur in 2012.

For both the three months and the nine months ended September 30, 2012, the changes in earnings attributable to noncontrolling interest at Otay Mesa VIE were due to changes in operating income.

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 short-term and long-term debt and distributions from our equity method investments.

Our committed lines of credit provide liquidity and support commercial paper.  As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein, in March 2012, Sempra Energy, Sempra Global (the holding company for our subsidiaries not subject to California utility regulation) and the California Utilities each entered into new five-year revolving credit facilities, expiring in 2017, which replaced the previous principal credit agreements that were scheduled to expire in 2014. At Sempra Energy and the California Utilities, the agreements are syndicated broadly among 24 different lenders and at Sempra Global, among 25 different lenders.  No single lender has greater than a 7-percent share in any agreement.

The table below shows the amount of available funds at September 30, 2012:

AVAILABLE FUNDS AT SEPTEMBER 30, 2012
(Dollars in millions)
		Sempra Energy
		Consolidated		SDG&E		SoCalGas
Unrestricted cash and cash equivalents		$	530	$	22	$	257
Available unused credit(1)			3,539		656		658
(1)	Borrowings on the shared line of credit at SDG&E and SoCalGas, discussed in Note 6 of the Notes to Condensed Consolidated Financial Statements herein, are limited to $658 million for each utility and $877 million in total. SDG&E’s available funds reflect commercial paper outstanding of $2 million, supported by the line.

Sempra Energy Consolidated

We believe thatthese available funds and cash flows from operations, distributions from equity method investments andsecurity issuances, combined with current cash balances, will be adequate to:

§   finance capital expenditures

§   meet liquidity requirements

§   fund shareholder dividends

§   fund new business acquisitions or start-ups

§   repay maturing long-term debt

In September 2012, Sempra Energy publicly offered and sold $500 million of 2.875-percent notes maturing in 2022, and SoCalGas publicly offered and sold $350 million of 3.75-percent first mortgage bonds maturing in 2042. In March 2012, Sempra Energy publicly offered and sold $600 million of 2.30-percent notes maturing in 2017, and SDG&E publicly offered and sold $250 million of 4.30-percent first mortgage bonds maturing in 2042. Sempra Energy and SDG&E issued long-term debt in 2011 in the aggregate principal amounts of $800 million and $600 million, respectively. Changing economic conditions could affect the availability and cost of both short-term and long-term financing. 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 the California Utilities, and secondarily our South American utilities. We continuously 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 three separate transactions during 2010 and one in early 2011, we and RBS sold substantially all of the businesses and assets of our joint-venture partnership that comprised our commodities-marketing businesses. Distributions from the partnership in 2011 were $623 million. The investment balance of $126 million at September 30, 2012 reflects remaining distributions expected to be received from the partnership as it is dissolved. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 10 of the Notes to Condensed Consolidated Financial Statements herein under “Other Litigation.”  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. We are providing transitional back-up guarantees, a few of which may continue for a prolonged period of time. Either RBS or JP Morgan Chase & Co., one of the buyers’ parties in the sales transactions, has fully indemnified us for any claims or losses in connection with the related transactions.

We provide additional information about RBS Sempra Commodities and the sales transactions and guarantees in Notes 4, 6 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 3, 4, 5 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

At September 30, 2012, our cash and cash equivalents held in foreign jurisdictions that are unavailable to fund domestic operations unless repatriated were approximately $240 million. We intend for funds associated with accumulated foreign earnings through September 30, 2012 to remain indefinitely in our foreign subsidiaries to fund their operations. We are currently considering a plan to repatriate future earnings from certain foreign operations beginning in 2013.

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, but may impact funding requirements for pension and other postretirement benefit plans. 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.

California Utilities

SDG&E and SoCalGas expect that cash flows from operations and debt issuances will continue to be adequate to meet their working capital and capital expenditure requirements. In March 2011, Sempra Energy made a $200 million capital contribution to SDG&E.

SoCalGas declared and paid a $100 million common dividend in the second quarter of 2012 and a $50 million common dividend in the first quarter of both 2012 and 2011. SoCalGas also declared and paid a $100 million common dividend in October 2012. However, as a result of the increase in SoCalGas’ capital investment programs over the next few years, management expects that SoCalGas’ dividends on common stock will be reduced, when compared to the dividends on common stock declared on an annual basis historically, or temporarily suspended over the next few years to maintain SoCalGas’ authorized capital structure during the periods of high capital investments.

As a result of SDG&E’s large capital investment program over the past few years and the level of capital investment in 2012, SDG&E does not expect to pay common dividends to Sempra Energy in 2012. However, due to the completion of construction of the Sunrise Powerlink transmission power line in June 2012, SDG&E expects to be able to resume the declaration and payment of dividends on its common stock in 2013.

Sempra South American Utilities

We expect projects at Chilquinta Energía and Luz del Sur to be funded by external borrowings and funds internally generated by Chilquinta Energía and Luz del Sur.

Sempra Mexico

We expect projects in Mexico to be funded through a combination of funds internally generated by the Mexico businesses, project financing, raising other external capital, and partnering in joint ventures.

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, low-cost financing from the U.S. Department of Energy (DOE), U.S. Treasury Department cash grants, funds from the parent, and partnering in joint ventures. The Sempra Renewables projects have planned in-service dates ranging from 2012 to 2016. In November 2012, Sempra Renewables received $253 million in funding from the DOE related to Mesquite Solar 1, at an interest rate of 2.262 percent.

Sempra Natural Gas

We expect Sempra Natural Gas to require funding from the parent and external sources to fund projects and investments, including development and expansion of its natural gas storage projects.

Cash flows from operations at Sempra Natural Gas are expected to decrease substantially since its contract with the DWR expired in September 2011, due to less favorable pricing on any replacement contracts obtained, and the sale of its El Dorado natural gas generation plant to SDG&E in 2011.  Also, Sempra Natural Gas may not be able to replace all of the lost revenue due to decreased market demand. Sales to the DWR comprised six percent of Sempra Energy’s revenues in 2011.

Some of Sempra Natural Gas’ long-term power sale contracts contain collateral requirements which require its affiliates and/or the counterparty to post cash, guarantees or letters of credit to the other party for exposure in excess of established thresholds. Sempra Natural Gas may be required to provide collateral when market price movements adversely affect the counterparty’s cost of replacement energy supplies if Sempra Natural Gas fails to deliver the contracted amounts. We have neither collateral posted nor owed to counterparties at September 30, 2012 pursuant to these requirements.

Sempra Natural Gas plans to develop a natural gas liquefaction export facility at its Cameron LNG terminal. Sempra Natural Gas expects the majority of the project to be project-financed and the balance provided by project partners in a joint venture agreement.

CASH FLOWS FROM OPERATING ACTIVITIES

CASH PROVIDED BY OPERATING ACTIVITIES
(Dollars in millions)
	2012		2012 Change				2011
Sempra Energy Consolidated	$	1,688	$	45	3	%	$	1,643
SDG&E		770		(49)	(6)			819
SoCalGas		746		251	51			495

Sempra Energy Consolidated

Cash provided by operating activities at Sempra Energy increased in 2012 primarily due to:

§   $130 million settlement payment in 2011 related to energy crisis litigation;

§   an $85 million payment received from Citizens Sunrise Transmission, LLC (Citizens) in July 2012, as discussed in Note 10 of the Notes to Condensed Consolidated Financial Statements herein;

§   $67 million higher net income, adjusted for noncash items included in earnings, in 2012 compared to 2011;

§   a $265 million decrease in accounts receivable in 2012 compared to a $218 million decrease in 2011;and

§   a $52 million increase in inventory in 2012 compared to a $93 million increase in 2011; offset by

§   $300 million of funds received in 2011 as compared to $190 million received in 2012 from wildfire litigation settlements; and

§   an increase of $220 million in net undercollected regulatory balancing accounts in 2012 compared to a decrease of $18 million in net overcollected regulatory balancing accounts in 2011. 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 explanation for changes in regulatory balances at SDG&E and SoCalGas below.

SDG&E

Cash provided by operating activities at SDG&E decreased in 2012 primarily due to:

§   $300 million of funds received in 2011 as compared to $190 million received in 2012 from wildfire litigation settlements; and

§   an increase of $220 million in net undercollected regulatory balancing accounts in 2012 as compared to an increase of $84 million in net overcollected regulatory balancing accounts in 2011, as follows:

o   the increase in net undercollected regulatory balancing accounts in 2012 was primarily due to:

§undercollection of electric resource costs of $141 million and

§undercollection of advanced metering infrastructure costs of $119 million;

o   the increase in net overcollected regulatory balancing accounts in 2011 was primarily due to:

§overcollection of electric resource costs of $41 million and

§overcollection of advanced metering infrastructure costs of $21 million; offset by

§   $189 million higher net income, adjusted for noncash items included in earnings, in 2012 compared to 2011;

§   an $85 million payment received from Citizens in July 2012; and

§   a $52 million increase in income taxes receivable in 2012 compared to a $130 million increase in 2011.

SoCalGas

Cash provided by operating activities at SoCalGas increased in 2012 primarily due to:

§   a $286 million decrease in accounts receivable in 2012 compared to a $221 million decrease in 2011;

§   a $16 million increase in inventory in 2012 compared to an $80 million increase in 2011;

§   a $33 million decrease in accounts payable in 2012 compared to an $83 million decrease in 2011; and

§   a decrease of $102 million in net overcollected regulatory balancing accounts in 2011, primarily due to:

o   overcollection of California alternate rates for energy (CARE) program costs of $27 million,

o   overcollection of direct assistance program costs of $27 million, and

o   overcollection of self-generation program costs of $26 million; offset by

§   $41 million lower net income, adjusted for noncash items included in earnings, in 2012 compared to 2011.

The table below shows the contributions to pension and other postretirement benefit plans for the nine months ended September 30, 2012.

			Other
	Pension		Postretirement
(Dollars in millions)	Benefits		Benefits
Sempra Energy Consolidated	$	111	$	32
SDG&E		36		10
SoCalGas		45		19

CASH FLOWS FROM INVESTING ACTIVITIES

CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
	2012		2012 Change				2011
Sempra Energy Consolidated	$	(2,576)	$	272	12	%	$	(2,304)
SDG&E		(992)		(191)	(16)			(1,183)
SoCalGas		(719)		124	21			(595)

Sempra Energy Consolidated

Cash used in investing activities at Sempra Energy increased in 2012 primarily due to:

§   a $210 million increase in capital expenditures;

§   $374 million in distributions received from RBS Sempra Commodities in 2011;

§   $249 million invested in Flat Ridge 2 in 2012; and

§   $30 million invested in Auwahi Wind in 2012; offset by

§   $611 million in cash used to fund Sempra South American Utilities’ purchase of South American entities in 2011.

SDG&E

Cash used in investing activities at SDG&E decreased in 2012 primarily due to a $164 million decrease in capital expenditures, primarily due to the completion of the Sunrise Powerlink project in June 2012.

SoCalGas

Cash used in investing activities at SoCalGas increased in 2012 due to:

§   a $161 million higher increase in the amount advanced to Sempra Energy in 2012 as compared to 2011; offset by

§   a $37 million decrease in capital expenditures.

ANNUAL CONSTRUCTION EXPENDITURES AND INVESTMENTS

The amounts and timing of capital expenditures are generally subject to approvals by the CPUC, the Federal Energy Regulatory Commission (FERC) and other regulatory bodies. However, in 2012, we expect to make annual capital expenditures and investments of approximately $3.3 billion. These expenditures include

§   $1.9 billion at the California Utilities for capital projects and plant improvements ($1.2 billion at SDG&E and $670 million at SoCalGas)

§   $1.4 billion at our other subsidiaries for capital projects in South America, renewable energy generation projects, and development of natural gas infrastructure

In 2012, the California Utilities expect their annual capital expenditures to include

§   $550 million for improvements to SDG&E’s natural gas and electric distribution systems

§   $200 million at SDG&E for the Sunrise Powerlink transmission line and substation expansions

§   $300 million for improvements to SDG&E’s electric transmission systems

§   $150 million for SDG&E’s electric generation plants and equipment

§   $670 million at SoCalGas for improvements to distribution and transmission systems and storage facilities, and for advanced metering infrastructure

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

In July 2012, SDG&E received $85 million from Citizens Sunrise Transmission, LLC, a subsidiary of Citizens Energy Corporation, pursuant to an agreement to provide access to a segment of the Sunrise Powerlink transmission line. The expected 2012 capital expenditure above for the Sunrise Powerlink is net of Citizens’ July 2012 payment. We discuss this agreement further in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.

For 2012, the expected annual capital expenditures and investments of $1.4 billion at our other subsidiaries, net of anticipated project financing and joint venture structures, include

Sempra South American Utilities

§   approximately $100 million to $200 million for capital projects in South America, including approximately $70 million for the Santa Teresa hydroelectric power plant at Luz del Sur

Sempra Mexico

§   approximately $170 million to $200 million for capital projects in Mexico, including approximately $150 million for the development of natural gas pipeline projects

Sempra Renewables

§   approximately $400 million for investment in the first phase (150 MW) of Mesquite Solar, a solar project at our Mesquite Power plant near Arlington, Arizona

§   approximately $350 million for investment in the second phase (150 MW) of Copper Mountain Solar, a solar project located near Boulder City, Nevada

§   approximately $150 million for investment in other renewable energy projects

Sempra Natural Gas

§   approximately $100 million for development of natural gas storage projects at Bay Gas Storage, LLC (Bay Gas) and Mississippi Hub, LLC (Mississippi Hub)

§   approximately $50 million to $100 million for other natural gas projects

Our level of capital expenditures and investments in the next few years may vary substantially and will depend on the cost and availability of financing, regulatory approvals, changes in U.S. federal tax law and business opportunities providing desirable rates of return.  We intend to finance our capital expenditures in a manner that will maintain our strong investment-grade credit ratings and capital structure.

CASH FLOWS FROM FINANCING ACTIVITIES

CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
	2012		2012 Change		2011
Sempra Energy Consolidated	$	1,157	$	753	$	404
SDG&E		215		(325)		540
SoCalGas		194		495		(301)

Sempra Energy Consolidated

Cash provided by financing activities at Sempra Energy increased in 2012 primarily due to:

§   $769 million higher issuances of debt, primarily due to an increase in issuances of long-term debt of $614 million ($1,910 million in 2012, compared to $1,296 million in 2011);

§   $158 million lower decrease in short-term debt; and

§   $80 million for the redemption of subsidiary preferred stock in 2011; offset by

§   $197 million higher debt payments, including $455 million higher payments of commercial paper with maturities greater than 90 days, offset by $258 million lower payments on long-term debt; and

§   an $80 million increase in common dividends paid.

SDG&E

Cash provided by financing activities at SDG&E decreased in 2012 primarily due to:

§   a $200 million capital contribution from Sempra Energy in 2011; and

§   $99 million lower issuances of long-term debt.

SoCalGas

SoCalGas financing activities provided cash in 2012 compared to using cash in 2011, primarily due to:

§   $348 million issuances of long-term debt in 2012; and

§   $250 million payment of long-term debt in 2011; offset by

§   a $100 million increase in common dividends paid.

COMMITMENTS

We discuss significant changes to contractual commitments at Sempra Energy, SDG&E and SoCalGas in Note 10 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 2012.

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 Updated Annual Report.

FACTORS INFLUENCING FUTURE PERFORMANCE

SEMPRA ENERGY OVERVIEW

California Utilities

The California Utilities’ operations have historically provided relatively stable earnings and liquidity. However, for the next few years, SoCalGas intends to limit its common stock dividends to reinvest its earnings in significant capital projects.

The California Utilities’ performance will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by the California legislature to address the state budget crisis 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 Note 9 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

SDG&E may also be significantly impacted by matters at San Onofre Nuclear Generating Station (SONGS). We discuss SONGS below and in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein, in Notes 6, 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report, in Item 1A. Risk Factors in Part II herein, and in Risk Factors in our Form 10-K.

Sempra South American Utilities

In April 2011, Sempra South American Utilities increased its investment in two utilities in South America. As anticipated, the acquisition continues to be accretive to our earnings per share. However, in connection with our increased interests in Chilquinta Energía and Luz del Sur, Sempra Energy has $1 billion in goodwill on its Consolidated Balance Sheet as of September 30, 2012. 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.

We discuss the acquisition in Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report. Sempra South American Utilities is also expected to provide earnings from construction projects when completed and other investments, but will require substantial funding for these investments.

In late 2011, Chilquinta Energía initiated the process to establish their distribution rates for the period from November 2012 to October 2016. Revenues at Chilquinta Energía are based on tariffs set by the National Energy Commission (Comisión Nacional de Energía, or CNE) every four years. We expect a final decision in the fourth quarter with the new distribution rates becoming effective in November 2012.

Sempra Renewables

Sempra Renewables is developing and investing in renewable energy generation projects that have long-term contracts with utilities. The renewable energy projects have planned in-service dates ranging from 2012 to 2016. These projects require construction financing which may come from a variety of sources including operating cash flow, project financing, low-cost financing procured under the DOE’s loan guaranty program, U.S. Treasury Department cash grants, 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 expects that its Mehoopany Wind Farm and Flat Ridge 2 Wind Farm projects will be placed in service in 2012. If all or any portion of these projects are not placed in service during 2012, Sempra Renewables’ cash flows and earnings within the next 10 years will be adversely affected as wind projects must be placed in service during 2012 in order to claim production tax credits.

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 Renewables Portfolio Standards (RPS). Additionally, the phase out or extension of U.S. federal income tax incentives, primarily investment tax credits and production tax credits, and grant programs could significantly impact future renewable energy resource availability and investment decisions.

Sempra Natural Gas

Current energy market prices are significantly lower than those under Sempra Natural Gas’ former contract with the DWR, which ended on September 30, 2011 and had provided a significant portion of Sempra Natural Gas’ revenues. Revenues from Sempra Natural Gas’ generation plants are also expected to be lower due to a decline in market demand and the sale of Sempra Natural Gas’ El Dorado natural gas generation plant to SDG&E on October 1, 2011. Based on current market prices for electricity, contracts that Sempra Natural Gas enters into at its natural gas-fired plant to replace the DWR contract, if obtained, or merchant (daily) sales will provide substantially lower earnings. Because Sempra Mexico sells power from its Mexicali plant to Sempra Natural Gas, its earnings from generation have decreased and may remain at lower levels due to the completion of the DWR contract.

In June 2011, Sempra Natural Gas entered into a 25-year contract with various members of Southwest Public Power Resources Group (SPPR Group), an association of 40 not-for-profit utilities in Arizona and southern Nevada, for 240 MW of electricity. Under the terms of the agreement, Sempra Natural Gas will provide 21 participating SPPR Group members with firm, day-ahead dispatchable power delivered to the Palo Verde hub beginning in January 2015.

At Sempra Natural Gas, until there are firm LNG supply or capacity services contracts from third parties that would subscribe to 100 percent of the capacity of Sempra Natural Gas’ Cameron terminal, Sempra Natural Gas will seek to purchase short-term LNG supplies and sell short-term capacity, which may result in greater variability in revenues and earnings. Sempra Natural Gas is currently evaluating opportunities to utilize its assets to support the liquefaction and exportation of LNG. The objective is to obtain a long-term contract and fully utilize our existing infrastructure while minimizing our future additional capital investment. In January 2012, the DOE approved Cameron LNG’s application for an LNG export license to Free Trade Act countries. The authorization to export LNG to countries with which the U.S. does not have a Free Trade Agreement is pending review by the DOE.

In April and May 2012, Sempra Natural Gas signed commercial development agreements with Mitsubishi Corporation, Mitsui & Co., Ltd., and a subsidiary of GDF SUEZ S.A. (GDF SUEZ) to develop a natural gas liquefaction export facility at the Cameron LNG terminal. The completed liquefaction facility is expected to be comprised of three liquefaction trains with a total export capability of 12 million tonnes per annum (Mtpa) of LNG, or approximately 1.7 Bcf per day. Sempra Natural Gas expects to receive the required permits from the FERC and enter into a turnkey contract in 2013 for engineering and construction services for the project. Pending regulatory approvals and the achievement of other key milestones, construction on the project is planned to start in 2013 and begin operations in 2017. The liquefaction facility will utilize Cameron LNG’s existing facilities, including two marine berths, three LNG storage tanks, and vaporization capability for regasification services of 1.5 Bcf per day. The anticipated incremental investment in the three-train liquefaction project is estimated to be approximately $6 billion, excluding capitalized interest, the majority of which will be project-financed and the balance provided by the project partners in a joint-venture arrangement.

The commercial development agreements bind the parties to fund all development expenses, including design, permitting and engineering, as well as to negotiate 20-year tolling agreements, based on agreed-upon key terms outlined in the commercial development agreements. Each tolling agreement would be for 4 Mtpa.

As we discuss above under “Overview–Sempra Natural Gas,” Sempra Natural Gas, KMP and Phillips 66 jointly own REX. We have recorded noncash, after-tax impairment charges of $179 million and $60 million in the second and third quarters of 2012, respectively, to write down our investment in the partnership that operates REX. We discuss our investment in Rockies Express and the impairment in Notes 4 and 8 of the Notes to Condensed Consolidated Financial Statements herein.

Sempra Commodities

In three separate transactions in 2010 and one in early 2011, we and RBS sold substantially all of the businesses and assets of our commodities-marketing partnership. The investment balance of $126 million at September 30, 2012 reflects remaining distributions expected to be received from the partnership as it is dissolved. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 10 of the Notes to Condensed Consolidated Financial Statements herein under “Other Litigation.” 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. We provide additional information in Notes 4, 6 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 3, 4, 5 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

CALIFORNIA UTILITIES

Joint Matters

General Rate Case (GRC)

Both SDG&E and SoCalGas have their 2012 General Rate Case (GRC) applications pending at the CPUC. The California Utilities filed their initial applications for the 2012 GRC in December 2010 to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements will change on an annual basis over the subsequent three-year (2013-2015) period. In July 2011, SDG&E and SoCalGas filed revised applications and in February 2012, SDG&E and SoCalGas filed amendments to update the July 2011 filing. The 2012 amendments revised the requested increases to their authorized revenue requirements, as compared to their 2011 authorized revenues, to $235 million at SDG&E, of which $67 million is for the cost recovery of incremental wildfire insurance premiums, and to $268 million at SoCalGas. The Division of Ratepayer Advocates is recommending that the CPUC reduce the utilities’ revenue requirements in 2012 by approximately 5 percent compared to 2011.

Evidentiary hearings were completed in January 2012 and final briefs reflecting the results from these hearings were filed with the CPUC in May 2012. The current CPUC schedule indicates a final decision for the 2012 GRC, which will be made effective retroactive to January 1, 2012, by the end of 2012. However, until such time as a final decision for the 2012 GRC is issued, the California Utilities are recording revenues in 2012 based on levels authorized in 2011 plus, for SDG&E, consistent with the recent CPUC decisions for cost recovery for SDG&E’s incremental wildfire insurance premiums, an amount for the recovery of 2012 wildfire insurance premiums. The timing of the CPUC decision and the outcome from these proceedings will have an impact on the financial condition, operating results and cash flows of the California Utilities. If the CPUC’s final decision grants a significantly lower authorized revenue requirement, it could have a material adverse effect on the California Utilities’ cash flows, financial position and results of operations starting in 2012 as compared to 2011. Also, if the CPUC does not issue a final decision for the 2012 GRC by December 31, 2012, Sempra Energy and the California Utilities will not be able to record the retroactive impact to January 1, 2012 of the final decision in their 2012 financial results, but would reflect the impact in 2013 financial results in the period in which such final decision is issued. We provide additional information regarding the 2012 GRC in Note 9 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to the Consolidated Financial Statements in the Updated Annual Report.

Cost of Capital

SDG&E and SoCalGas filed separate applications with the CPUC in April 2012 to update their cost of capital effective January 1, 2013. SDG&E proposes to adjust its authorized capital structure by increasing the amount of its common equity from 49.0 percent to 52.0 percent. SDG&E also proposes to lower its authorized return on equity (ROE) from 11.1 percent to 11.0 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized return on rate base (ROR) from 8.40 percent to 8.15 percent. SoCalGas proposes to adjust its authorized capital structure by increasing the amount of its common equity from 48.0 percent to 52.0 percent. SoCalGas proposes to increase its authorized ROE from 10.82 percent to 10.9 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized ROR from 8.68 percent to 8.44 percent.

The proposed change in SDG&E’s capital structure and resulting ROR would result in a decrease in its 2013 authorized revenue of approximately $9.1 million if approved by the CPUC. The proposed change in SoCalGas’ capital structure and resulting ROR would result in a decrease in its 2013 authorized revenue of approximately $0.8 million if approved by the CPUC.

If the CPUC were to approve a capital structure in the cost of capital proceedings that resulted in either SDG&E’s or SoCalGas’ ROR being significantly lower than what was proposed, it could materially adversely affect the respective company’s cash flows, financial position and results of operations starting in 2013.

SDG&E proposes to continue its currently approved cost of capital adjustment mechanism, which uses a utility bond benchmark. SoCalGas proposes to switch from its current cost of capital adjustment mechanism, which is based on U.S. Treasury Bonds, to a mechanism which uses a utility bond benchmark similar to SDG&E, Southern California Edison (Edison) and Pacific Gas and Electric Company (PG&E). We provide more information about the cost of capital proceedings in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.

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 its natural gas pipeline operations and investments. In August 2011, SoCalGas, SDG&E, PG&E and Southwest Gas filed implementation plans with the CPUC to test or replace all natural gas transmission pipelines that have not been pressure tested, as we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report. The California Utilities are currently estimating that the total cost for Phase 1 of the two-phase plan is $3.1 billion over a 10-year period. 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 are outside the scope of the 2012 GRC proceedings discussed above. If the CPUC were to decide that the incremental capital investment not be considered as incremental rate base outside the GRC process or that this incremental capital investment earn an ROR lower than what is otherwise authorized, it could materially adversely affect the respective company’s cash flows, financial position and results of operations upon commencement of this program. We provide additional information in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.

SDG&E Matters

2007 Wildfire Litigation

In regard to the 2007 wildfire litigation, SDG&E’s settlement of claims and the estimate of outstanding claims and legal fees is approximately $2.3 billion, which is in excess of the $1.1 billion of liability insurance coverage and the approximately $824 million received or receivable from third parties. However, SDG&E has concluded that it is probable that it will be permitted to recover from its utility customers substantially all reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and amounts recovered from other responsible parties. Consequently, Sempra Energy and SDG&E expect no significant earnings impact from the resolution of the remaining wildfire claims. As of September 30, 2012, Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets reflect $326 million in Regulatory Assets Arising From Wildfire Litigation Costs, including $292 million related to CPUC operations, for costs incurred and the estimated settlement of pending claims. However, SDG&E’s cash flow may be materially adversely affected by timing differences between the resolution of claims and recoveries from utility customers, which may extend over a number of years. In addition, recovery from customers will require future regulatory actions, and a failure to obtain substantial or full recovery, 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.

SDG&E will continue to gather information to evaluate and assess the remaining wildfire claims and the likelihood, amount and timing of recoveries from utility customers and will make appropriate adjustments to wildfire reserves and the related regulatory assets as additional information becomes available.

Should SDG&E conclude that the amount of recovery of excess wildfire costs from utility customers is no longer reasonably estimable or that recovery is no longer probable, at that time SDG&E will record a charge against earnings. In addition, in periods following any such conclusion by SDG&E that recovery is no longer probable, Sempra Energy’s and SDG&E’s earnings will be adversely impacted by increases in the estimated costs to settle pending wildfire claims.

We provide additional information concerning these matters in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

SONGS

As a result of the extended outage at SONGS, the CPUC has issued an Order Instituting Investigation (OII) to determine whether SDG&E should remove from customer rates some or all revenue requirement associated with the portion of the facility that is out of service. This OII will consolidate all SONGS issues from related regulatory proceedings and consider the appropriate cost recovery for SONGS, including among other costs, the cost of the steam generator replacement project, replacement power costs, capital expenditures, operation and maintenance costs and seismic study costs. The OII requires that all costs related to SONGS incurred since January 1, 2012 be tracked in a separate memorandum account, with all revenues collected in recovery of such costs subject to refund, and will address the extent to which such revenues, if any, will be required to be refunded to customers.

Currently, SDG&E is collecting in customer rates its share of the operating costs, depreciation and return on its investment in SONGS. For the nine-month period ended September 30, 2012, SDG&E has recognized (and collected through customer rates) an estimated $153 million of revenue associated with its investment in SONGS and operating costs. At September 30, 2012, SDG&E’s weighted average rate base investment in SONGS was approximately $220 million and its net book investment, including construction work in progress and nuclear fuel was $485 million. If the CPUC were to order SDG&E to remove all or most of the authorized revenue requirement associated with SONGS from customer rates, refund all or most of the revenue from its investment in SONGS charged to customers since January 1, 2012, or remove all or most of SDG&E’s rate base investment in SONGS from its rate base, it would likely have a material adverse effect on Sempra Energy’s and SDG&E’s financial condition, cash flows and results of operations.

We provide additional information concerning SONGS in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 6, 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

OTHER SEMPRA ENERGY MATTERS

We discuss additional potential and expected impacts of the 2010 Tax Act on our income tax expense, earnings and cash flows in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” above.

We may be further impacted by depressed and rapidly changing economic conditions. Moreover, the dollar has fluctuated 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 “Market Risk – Foreign Currency Rate Risk” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Updated Annual Report. North American natural gas prices, which affect profitability at Sempra Renewables and Sempra Natural Gas, are currently significantly below Asian and European prices. These factors could, if they remain unchanged, adversely affect profitability. However, management expects that future export capability at Sempra Natural Gas’ Cameron LNG facility would benefit from lower gas prices in North America compared to other regions.

We discuss additional matters that could affect our future performance in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

FINANCIAL DERIVATIVES REFORMS

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 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 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 of our hedging programs, because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to mitigate.

LITIGATION

We describe legal proceedings which could adversely affect our future performance in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.

CALIFORNIA UTILITIES – INDUSTRY DEVELOPMENTS AND CAPITAL PROJECTS

We describe capital projects, electric and natural gas regulation and rates, and other pending proceedings and investigations that affect our business in Note 9 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

SEMPRA INTERNATIONAL AND SEMPRA U.S. GAS & POWER INVESTMENTS

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 “Capital Resources and Liquidity” and “Factors Influencing Future Performance” in the Updated Annual Report.

Sempra South American Utilities

Santa Teresa

In May 2011, groundbreaking took place for Santa Teresa, a project at Luz del Sur to build a 98-MW hydroelectric power plant in Peru’s Cusco region. It is planned to be completed in 2014.

Transmission Projects

In May 2012, Chilquinta Energía, in a joint venture with Sociedad Austral de Electricidad Sociedad Anonima (SAESA), was awarded two 220-kilovolt (kV) transmission lines in Chile. The transmission lines will extend 150 miles, and we estimate it will cost approximately $160 million and be completed in 2017.

Sempra Mexico

Energía Sierra Juárez

In April 2011, SDG&E entered into a 20-year contract for up to 156 MW of renewable power supplied from the first phase of Sempra Mexico’s Energía Sierra Juárez wind project in Baja California, Mexico. The contract was approved by the CPUC in March 2012 and by the FERC in July 2012. We expect construction on the project to begin in 2013, and the project to be fully operational in 2014.

Sempra Mexico intends to develop the project within the framework of a joint venture, and is working on an agreement for the sale of a 50-percent partnership interest in the current phase of the project to BP Wind Energy.

Pipeline Projects

In October 2012, Sempra Mexico was awarded two contracts by CFE to build and operate an approximately 500-mile pipeline network to transport natural gas from the US-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 and be completed by the second half of 2016. The capacity is fully contracted by CFE under two 25-year contracts denominated in U.S. dollars. Our ability to secure rights of way and construct the lines within budgeted amounts will impact future performance.

Sempra Renewables

Copper Mountain Solar

Copper Mountain Solar is a photovoltaic generation facility operated and under development by Sempra Renewables in Boulder City, Nevada. If fully developed, the project will be capable of producing up to approximately 450 MW of solar power; it is being developed in multiple phases as contracted. Copper Mountain Solar is comprised of two separate projects. Copper Mountain Solar 1 is a 58-MW photovoltaic generation facility currently in operation, and now includes the 10-MW facility previously referred to as El Dorado Solar.

Copper Mountain Solar 2 (CMS 2) began construction in December 2011 and will total 150 MW when completed. CMS 2 is divided into two phases, with the first phase of 92 MW planned to be placed in service by the end of 2012 and the remaining 58 MW planned to be placed in service in 2015. PG&E has contracted for all of the solar power at CMS 2 for 25 years.

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. Construction on the first phase (Mesquite Solar 1) of 150 MW began in June 2011 and is expected to be placed in service by the end of 2012. In December 2011, Mesquite Solar 1 began delivering 42 MW of electricity to the grid. At September 30, 2012, the project is at 126 MW of capacity. PG&E has contracted for all of the solar power at Mesquite Solar 1 for 20 years.

Auwahi Wind

The Auwahi Wind project, in the southeastern region of Maui, is a joint venture with BP Wind Energy. The project has a 20-year contract with Maui Electric Company to provide 21 MW of wind energy. Significant project costs were incurred during late 2011, and physical construction began on the project in March 2012. We expect the project to be placed in service by the end of 2012.

Mehoopany Wind Farm

In December 2011, Sempra Renewables entered into a joint venture with BP Wind Energy to develop the Mehoopany Wind Farm in Wyoming County, Pennsylvania, which is expected to generate up to 141 MW of energy. The power output from the wind farm has been sold under 20-year contracts to Old Dominion Electric Cooperative and Southern Maryland Electric Cooperative Inc. The wind farm is in full construction and we expect the project to be placed in service by the end of 2012.

Flat Ridge 2 Wind Farm

In December 2011, Sempra Renewables entered into a joint venture with BP Wind Energy to develop the Flat Ridge 2 Wind Farm near Wichita, Kansas, which is expected to generate up to 419 MW of energy. The power output from the wind farm has been sold under three contracts for 20 to 25 year terms, including contracts with Associated Electric Cooperative, Inc. and Southwestern Electric Power Company, and construction began in April 2012. In June 2012, Sempra Renewables entered into an agreement with BP Wind Energy for a 51-MW expansion of Flat Ridge 2, the power output of which has been sold under a purchase power agreement with Arkansas Electric Cooperative approved by the Rural Utilities Service in April 2012. We expect both the original 419-MW and 51-MW expansion of Flat Ridge 2 to be placed in service by the end of 2012.

Sempra Natural Gas

Natural Gas Storage

Currently, Sempra Natural Gas has 30 Bcf of operational working natural gas storage capacity. We are currently developing another 13 Bcf of capacity with planned in-service dates through 2013 and may, over the long term, develop as much as 76 Bcf of total storage capacity.

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, previously referred to as Liberty natural gas storage expansion, a salt cavern development project in Cameron Parish, Louisiana. Sempra Natural Gas owns 75 percent of the project and ProLiance Transportation LLC owns the remaining 25 percent. The project’s location provides access to several LNG facilities in the area.

Cameron LNG

In April and May 2012, Sempra Natural Gas signed commercial development agreements with Mitsubishi Corporation, Mitsui & Co., Ltd., and GDF SUEZ to develop a natural gas liquefaction export facility at the site of its Cameron LNG terminal in Hackberry, Louisiana. We discuss these agreements above in “Factors Influencing Future Performance – Sempra Energy Overview.”

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 Updated Annual Report.

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

NEW ACCOUNTING STANDARDS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We provide disclosure regarding derivative activity in Note 7 of the Notes to Condensed Consolidated Financial Statements herein. We discuss our market risk and risk policies in detail in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Updated Annual Report.

INTEREST RATE RISK

The table below shows the nominal amount and the one-year VaR for long-term debt, excluding commercial paper classified as long-term debt, capital lease obligations and interest rate swaps, and before reductions for unamortized discount, at September 30, 2012 and December 31, 2011:

	Sempra Energy
	Consolidated				SDG&E				SoCalGas
	Nominal		One-Year		Nominal		One-Year		Nominal		One-Year
(Dollars in millions)	Debt		VaR(1)		Debt		VaR(1)		Debt		VaR(1)
At September 30, 2012:
California Utilities fixed-rate	$	5,452	$	830	$	3,790	$	622	$	1,662	$	208
California Utilities variable-rate		347		18		347		18		―		―
All other, fixed-rate and variable-rate		5,906		387		―		―		―		―
At December 31, 2011:
California Utilities fixed-rate	$	4,617	$	782	$	3,304	$	623	$	1,313	$	159
California Utilities variable-rate		591		25		591		25		―		―
All other, fixed-rate and variable-rate		4,602		377		―		―		―		―
(1) After the effects of interest rate swaps.

At September 30, 2012, the net notional amount of interest rate swap transactions ranged from $6 million to $369 million at Sempra Energy (ranges relate to the tenor of the various hedging instruments).  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 rate risk in detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Updated Annual Report. At September 30, 2012, there were no significant changes to our exposure to foreign currency rate risk since December 31, 2011.

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, 2012, 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 and 10 of the Notes to Condensed Consolidated Financial Statements herein and Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report, or 2) referred to in “Management's Discussion and Analysis of Financial Condition and Results of Operations” herein and in the Updated Annual Report.

ITEM 1A. RISK FACTORS

The following supplements the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2011.

Recovery of 2007 Wildfire Litigation Costs

SDG&E is subject to numerous lawsuits arising out of the San Diego County wildfires in 2007. To date, SDG&E’s costs to settle these claims and its estimated future settlement costs and defense costs have exceeded its $1.1 billion of liability insurance coverage and the approximately $824 million received or receivable from other responsible parties. SDG&E is seeking to recover from its utility customers substantially all of its reasonably incurred costs of resolving 2007 wildfire claims in excess of its liability insurance coverage and amounts recovered from other responsible parties. SDG&E has concluded that it is probable that SDG&E will be permitted to recover these excess costs from its utility customers, and at September 30, 2012, Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets include assets of $326 million in Regulatory Assets Arising From Wildfire Litigation Costs, of which $292 million is related to CPUC operations, with respect to these excess costs. However, recovery of these amounts from utility customers will require future regulatory actions.

In August 2009, SDG&E and SoCalGas filed an application with the CPUC proposing a new mechanism for the future recovery of all wildfire-related expenses for claims, litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC for recovery in distribution rates. In October 2012, the Administrative Law Judge’s draft decision (the Proposed Decision or PD) and the Assigned Commissioner’s alternate draft decision (the Alternate Decision or AD) in this proceeding were issued. The PD rejects SDG&E’s and SoCalGas’ request for a new balancing account and cost recovery mechanism. The AD approves SDG&E’s and SoCalGas’ request for a new balancing account and cost recovery mechanism, but only for wildfire events that occur after July 2010 and only for wildfires for which the utility is found not to be at fault. The AD also directs SDG&E to remove any amounts recorded in the balancing account associated with the 2007 wildfires. Following the issuance of the PD and the AD and consistent with CPUC rules and procedures, SDG&E requested an ex parte meeting with the Assigned Commissioner and staff. The request was granted, and the ex parte meeting was held on October 29, 2012. At the meeting, SDG&E provided information to the Assigned Commissioner addressing key issues from the AD that SDG&E believes contradict prior CPUC rulings and decisions. While there can be no assurance that the Assigned Commissioner will amend the AD, given the relevant regulatory and statutory standards and the issues discussed at the ex parte meeting, SDG&E has concluded that it remains probable that SDG&E will be permitted to recover from ratepayers substantially all of its reasonably incurred costs associated with the 2007 wildfires that exceed the amounts recovered from its insurance coverage and other responsible third parties. For a description of this proceeding and information about 2007 wildfire litigation costs and their recovery, see Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements included in Part I—Item 1 of this report.

SDG&E will continue to assess the recovery of these excess wildfire costs from ratepayers. Should SDG&E conclude that the amount of the recovery from ratepayers is no longer reasonably estimable or that recovery 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 such recovery was no longer probable or reasonably estimable as of September 30, 2012, the resulting after-tax charge against earnings would have been approximately $175 million. In addition, in periods following any such conclusion, SDG&E’s earnings will be adversely impacted by increases in the estimated costs to settle pending wildfire claims.

As noted above, recovery from customers will require future regulatory actions, and a failure to obtain all or a significant portion of the expected recovery, or a conclusion that recovery from ratepayers is no longer probable, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s cash flows, financial condition and results of operations. In addition, if recovery is permitted, Sempra Energy’s and SDG&E’s cash flows may be materially adversely affected due to the timing differences between resolution of claims and the recovery from utility customers, which may extend over a number of years.

Ongoing regulatory and maintenance issues at San Onofre Nuclear Generating Station (SONGS)

SDG&E has a 20-percent ownership interest in SONGS, a 2,150-MW nuclear generating facility near San Clemente, California operated by Southern California Edison. As discussed in Note 9 of the Notes to Condensed Consolidated Financial Statements herein, SONGS’s Units 2 and 3 are offline. The timing of the restart of either of these Units is dependent upon approval by the Nuclear Regulatory Commission, which could result in substantial additional expenditures that may not be recoverable, in whole or in part, in customer rates. If one or both of these Units were to be offline for more than nine consecutive months (November 2012 for Unit 3 and December 2012 for Unit 2), the CPUC will be notified of such fact. In November 2012, the CPUC issued an Order Instituting Investigation (OII) into the SONGS outage to determine whether SDG&E should remove from customer rates some or all revenue requirement associated with the portion of the facility that is out of service. This OII will consolidate all SONGS issues from related regulatory proceedings and consider the appropriate cost recovery for SONGS, including among other costs, the cost of the steam generator replacement project, replacement power costs, capital expenditures, operation and maintenance costs and seismic study costs. The OII requires all costs related to SONGS incurred since January 1, 2012 be tracked in a separate memorandum account, with all revenues collected in recovery of such costs subject to refund, and will address the extent to which such revenues, if any, will be required to be refunded to customers.  Any extended shut down of one or both of these Units and the costs required to bring those Units back online could materially adversely affect SDG&E’s and Sempra Energy’s businesses, results of operations, cash flows, and financial condition.  In addition, any decision by the CPUC to require SDG&E to refund some or all of the revenues collected in recovery of the costs described above could materially adversely affect SDG&E’s and Sempra Energy’s businesses, results of operations, cash flows, and financial condition.

ITEM 6. EXHIBITS

The following exhibits relate to each registrant as indicated.

EXHIBIT 3 -- BYLAWS AND ARTICLES OF INCORPORATION
Sempra Energy
3.1		Amended Bylaws of Sempra Energy effective September 13, 2012 (Sempra Energy Form 8-K filed on September 17, 2012, Exhibit 3(ii)).
EXHIBIT 10 -- MATERIAL CONTRACTS
Sempra Energy / Southern California Gas Company
10.1		Severance Pay Agreement between Sempra Energy and Dennis Arriola.
EXHIBIT 12 -- STATEMENTS RE: COMPUTATION OF RATIOS
Sempra Energy
12.1	Sempra Energy Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
San Diego Gas & Electric Company
12.2	San Diego Gas & Electric Company Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
Southern California Gas Company
12.3	Southern California Gas Company Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
EXHIBIT 31 -- SECTION 302 CERTIFICATIONS
Sempra Energy
31.1	Statement of Sempra Energy’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.2	Statement of Sempra Energy’s Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
San Diego Gas & Electric Company
31.3	Statement of San Diego Gas & Electric Company’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.4	Statement of San Diego Gas & Electric Company’s Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
Southern California Gas Company
31.5	Statement of Southern California Gas Company’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.6	Statement of Southern California Gas Company’s Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
EXHIBIT 32 -- SECTION 906 CERTIFICATIONS
Sempra Energy
32.1	Statement of Sempra Energy’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.2	Statement of Sempra Energy’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
San Diego Gas & Electric Company
32.3	Statement of San Diego Gas & Electric Company’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.4	Statement of San Diego Gas & Electric Company’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
Southern California Gas Company
32.5	Statement of Southern California Gas Company’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.6	Statement of Southern California Gas Company’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
EXHIBIT 101 -- INTERACTIVE DATA FILE
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 6, 2012	By:  /s/ Trevor I. Mihalik
	Trevor I. Mihalik 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 6, 2012	By:  /s/ Robert M. Schlax
	Robert M. Schlax 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 6, 2012	By:  /s/ Robert M. Schlax
	Robert M. Schlax Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

EX-10

Exhibit 10.1

EX-12

EXHIBIT 12.1
SEMPRA ENERGY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)
							September 30,
		2007	2008(1)	2009(1)	2010(1)	2011(1)	2012
Fixed charges and preferred stock dividends:
Interest		$           379	$           353	$           455	$           492	$           549	$             438
Interest portion of annual rentals		6	3	2	3	2	2
Preferred dividends of subsidiaries (2)		14	13	13	11	10	5
Total fixed charges		399	369	470	506	561	445
Preferred dividends for purpose of ratio		-	-	-	-	-	-
Total fixed charges and preferred dividends for purpose of ratio		$           399	$           369	$           470	$           506	$           561	$             445
Earnings:
Pretax income from continuing operations before adjustment for income or loss from equity investees		$         1,538	$         1,009	$           977	$         1,079	$         1,747	$          1,009
Add:
Total fixed charges (from above)		399	369	470	506	561	445
Distributed income of equity investees		19	133	493	260	96	37
Less:
Interest capitalized		100	100	73	74	27	41
Preferred dividends of subsidiaries (2)		10	10	13	11	10	5
Total earnings for purpose of ratio		$         1,846	$         1,401	$         1,854	$         1,760	$         2,367	$          1,445
Ratio of earnings to combined fixed charges and preferred stock dividends		4.63	3.80	3.94	3.48	4.22	3.25
Ratio of earnings to fixed charges		4.63	3.80	3.94	3.48	4.22	3.25
(1)	As adjusted for the retrospective effect of a change in accounting principle. This change had no impact at December 31, 2007 or for the year then ended.
(2)	In computing this ratio, “Preferred dividends of subsidiaries” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

EX-12

EXHIBIT 12.2
SAN DIEGO GAS & ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)
							September 30,
		2007	2008	2009	2010	2011	2012
Fixed Charges and Preferred Stock Dividends:
Interest		$            105	$            107	$            118	$            153	$            193	$               163
Interest portion of annual rentals		3	1	1	1	1	1
Total fixed charges		108	108	119	154	194	164
Preferred stock dividends (1)		7	7	7	7	7	6
Combined fixed charges and preferred stock dividends for purpose of ratio		$            115	$            115	$            126	$            161	$            201	$               170
Earnings:
Pretax income from continuing operations		$            406	$            451	$            550	$            531	$            692	$               552
Total fixed charges (from above)		108	108	119	154	194	164
Less: Interest capitalized		3	13	4	1	1	-
Total earnings for purpose of ratio		$            511	$            546	$            665	$            684	$            885	$               716
Ratio of earnings to combined fixed charges and preferred stock dividends		4.44	4.75	5.28	4.25	4.40	4.21
Ratio of earnings to fixed charges		4.73	5.06	5.59	4.44	4.56	4.37
(1)	In computing this ratio, “Preferred stock dividends” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

EX-12

EXHIBIT 12.3
SOUTHERN CALIFORNIA GAS COMPANY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)
							September 30,
		2007	2008	2009	2010	2011	2012
Fixed Charges:
Interest		$             72	$             65	$             74	$             72	$             77	$                57
Interest portion of annual rentals		3	2	1	2	1	1
Total fixed charges		75	67	75	74	78	58
Preferred stock dividends (1)		2	2	2	2	2	2
Combined fixed charges and preferred stock dividends for purpose of ratio		$             77	$             69	$             77	$             76	$             80	$                60
Earnings:
Pretax income from continuing operations		$            391	$            385	$            418	$            463	$            431	$              296
Add: Total fixed charges (from above)		75	67	75	74	78	58
Less: Interest capitalized		1	-	1	1	1	-
Total earnings for purpose of ratio		$            465	$            452	$            492	$            536	$            508	$              354
Ratio of earnings to combined fixed charges and preferred stock dividends		6.04	6.55	6.39	7.05	6.35	5.90
Ratio of earnings to fixed charges		6.20	6.75	6.56	7.24	6.51	6.10
(1)	In computing this ratio, “Preferred stock dividends” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

EX-31

EXHIBIT 31.1

CERTIFICATION

I, Debra L. Reed, certify that:

1.

I have reviewed this report on Form 10-Q of Sempra Energy;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

November 6, 2012

/S/  Debra L. Reed

Debra L. Reed

Chief Executive Officer

EX-31

EXHIBIT 31.2

CERTIFICATION

I, Joseph A. Householder, certify that:

1.

I have reviewed this report on Form 10-Q of Sempra Energy;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

November 6, 2012

/S/  Joseph A. Householder

Joseph A. Householder

Chief Financial Officer

EX-31

EXHIBIT 31.3

CERTIFICATION

I, Jessie J. Knight, Jr., certify that:

1.

I have reviewed this report on Form 10-Q of San Diego Gas & Electric Company;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

November 6, 2012

/S/  Jessie J. Knight, Jr.

Jessie J. Knight, Jr.

Chief Executive Officer

EX-31

EXHIBIT 31.4

CERTIFICATION

I, Robert M. Schlax, certify that:

1.

I have reviewed this report on Form 10-Q of San Diego Gas & Electric Company;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

November 6, 2012

/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

EX-31

EXHIBIT 31.5

CERTIFICATION

I, Anne S. Smith, certify that:

1.

I have reviewed this report on Form 10-Q of Southern California Gas Company;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

November 6, 2012

/S/  Anne S. Smith

Anne S. Smith

Chief Executive Officer

EX-31

EXHIBIT 31.6

CERTIFICATION

I, Robert M. Schlax, certify that:

1.

I have reviewed this report on Form 10-Q of Southern California Gas Company;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

November 6, 2012

/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

EX-32

Exhibit 32.1

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Sempra Energy (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2012 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 6, 2012

/S/  Debra L. Reed

Debra L. Reed

Chief Executive Officer

EX-32

Exhibit 32.2

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Sempra Energy (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2012 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 6, 2012

/S/  Joseph A. Householder

Joseph A. Householder

Chief Financial Officer

EX-32

Exhibit 32.3

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of San Diego Gas & Electric Company (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2012 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 6, 2012

/S/  Jessie J. Knight, Jr.

Jessie J. Knight, Jr.

Chief Executive Officer

EX-32

Exhibit 32.4

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of San Diego Gas & Electric Company (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2012 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 6, 2012

/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

EX-32

Exhibit 32.5

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Southern California Gas Company (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2012 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 6, 2012

/S/  Anne S. Smith

Anne S. Smith

Chief Executive Officer

EX-32

Exhibit 32.6

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Southern California Gas Company (the "Company") certifies that:

(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2012 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 6, 2012

/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

XML

OTHER FINANCIAL DATA - OTHER INCOME (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net	$ 44		$ 12	[1]	$ 137		$ 86	[1]
San Diego Gas and Electric Company and Subsidiary [Member]
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net	5		26		59		55
Southern California Gas Company [Member]
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net	6		3		14		9
Allowance for Cost of Equity Funds Used During Construction [Member]
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net	13		26		80		67
Allowance for Cost of Equity Funds Used During Construction [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net	6		21		61		54
Allowance for Cost of Equity Funds Used During Construction [Member] | Southern California Gas Company [Member]
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net	7		5		19		13
Regulatory Interest, Net [Member]
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net			0	[2]	1	[2]	1	[2]
Regulatory Interest, Net [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net			0	[2]	1	[2]	1	[2]
Gains (losses) on interest rate and foreign exchange instruments [Member]
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net	1		(26)		11		(14)
Gain (Loss) on Investments [Member]
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net	17	[3]	(6)	[3]	27	[3]	13	[3]
Other Income, Sundry [Member]
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net	13		18		18		19
Other Income, Sundry [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net	(1)		5		(3)		0
Other Income, Sundry [Member] | Southern California Gas Company [Member]
Component of Other Income, Nonoperating [Line Items]
Other income (expense), net	$ (1)		$ (2)		$ (5)		$ (4)

[1] As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

[2] Interest on regulatory balancing accounts.

[3] Represents investment gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.

XML

FAIR VALUE MEASUREMENTS 5 (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012		Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments, Fair Value Disclosure	$ 1		$ 5
Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments, Fair Value Disclosure	1		5
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments, Fair Value Disclosure	16	[1]	21	[1]
Fair value of financial instruments, Total long-term debt	11,727	[2]	9,826	[2]
Preferred Stock Of Subsidiaries Fair Value Disclosure	99		99
Debt Instrument Unamortized Discount	17		16
Capital Lease Obligations	192		204
Commercial Paper Noncurrent			400
Carrying Amount | San Diego Gas and Electric Company and Subsidiary [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of financial instruments, Total long-term debt	4,137	[3]	3,895	[3]
Contingently Redeemable Preferred Stock Fair Value Disclosure	79		79
Debt Instrument Unamortized Discount	12		11
Capital Lease Obligations	187		193
Carrying Amount | Southern California Gas Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of financial instruments, Total long-term debt	1,662	[4]	1,313	[4]
Preferred Stock Fair Value Disclosure	22		22
Debt Instrument Unamortized Discount	4		3
Capital Lease Obligations	5		11
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments, Fair Value Disclosure	46	[1]	48	[1]
Fair value of financial instruments, Total long-term debt	13,311	[2]	11,047	[2]
Preferred Stock Of Subsidiaries Fair Value Disclosure	108		106
Fair Value | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of financial instruments, Total long-term debt	12,556	[2]	10,447	[2]
Preferred Stock Of Subsidiaries Fair Value Disclosure	108		106
Fair Value | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Investments, Fair Value Disclosure	46	[1]	48	[1]
Fair value of financial instruments, Total long-term debt	755	[2]	600	[2]
Fair Value | San Diego Gas and Electric Company and Subsidiary [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of financial instruments, Total long-term debt	4,655	[3]	4,288	[3]
Contingently Redeemable Preferred Stock Fair Value Disclosure	86		86
Fair Value | San Diego Gas and Electric Company and Subsidiary [Member] | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of financial instruments, Total long-term debt	4,308	[3]	3,933	[3]
Contingently Redeemable Preferred Stock Fair Value Disclosure	86		86
Fair Value | San Diego Gas and Electric Company and Subsidiary [Member] | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of financial instruments, Total long-term debt	347	[3]	355	[3]
Fair Value | Southern California Gas Company [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of financial instruments, Total long-term debt	1,872	[4]	1,506	[4]
Preferred Stock Fair Value Disclosure	24		23
Fair Value | Southern California Gas Company [Member] | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of financial instruments, Total long-term debt	1,872	[4]	1,506	[4]
Preferred Stock Fair Value Disclosure	$ 24		$ 23

[1] We discuss our investments in affordable housing partnerships in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

[2] Before reductions for unamortized discount (net of premium) of $17 million at September 30, 2012 and $16 million at December 31, 2011, and excluding capital leases of $192 million at September 30, 2012 and $204 million at December 31, 2011, and commercial paper classified as long-term debt of $400 million at December 31, 2011. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

[3] Before reductions for unamortized discount of $12 million at September 30, 2012 and $11 million at December 31, 2011, and excluding capital leases of $187 million at September 30, 2012 and $193 million at December 31, 2011.

[4] Before reductions for unamortized discount of $4 million at September 30, 2012 and $3 million at December 31, 2011, and excluding capital leases of $5 million at September 30, 2012 and $11 million at December 31, 2011.

XML

DERIVATIVE FINANCIAL INSTRUMENTS 5 (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Sep. 30, 2012
Cash Flow Hedge Disclosure [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ (18)
Maximum length of time hedged in cash flow hedge	17
Joint Venture Maximum Length Of Time Hedged In Cash Flow Hedge	18
Cash flow hedge ineffectiveness	1
San Diego Gas and Electric Company and Subsidiary [Member]
Cash Flow Hedge Disclosure [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	(8)
Maximum length of time hedged in cash flow hedge	7
Southern California Gas Company [Member]
Cash Flow Hedge Disclosure [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ (1)

XML

FAIR VALUE MEASUREMENTS 6 (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Sep. 30, 2012
Fair Value Inputs Assets Quantitative Information [Line Items]
Investment in RBS Sempra Commodities LLP	$ 126
Investment in Rockies Express	$ 369
Fair value measurement percentage, of level two hierarchy, for Rockies Express	67.00%
Fair value measurement percentage, of level three hierarchy, for Rockies Express	33.00%
Fair value measurement percentage, of level three hierarchy, for RBS Sempra Commodities	100.00%
Equity Method Investments [Member] | Market Approach Valuation Technique [Member] | Level 2 | Sixty Seven Percent [Member] | Stated [Member]
Fair Value Inputs Assets Quantitative Information [Line Items]
Fair value inputs, equity sale offer price	100.00%
Equity Method Investments [Member] | Probability Weighted Discounted Cash Flow Valuation Technique [Member] | Level 3 | Thirty Three Percent [Member] | Maximum [Member]
Fair Value Inputs Assets Quantitative Information [Line Items]
Fair value inputs, combined transportation rate assumption	78.00%	[1]
Fair value inputs, operating and maintenance escalation rate	1.00%
Fair value inputs, forecasted interest rate on debt to be refinanced	10.00%
Fair value inputs, discount rate	10.00%
Equity Method Investments [Member] | Probability Weighted Discounted Cash Flow Valuation Technique [Member] | Level 3 | Thirty Three Percent [Member] | Minimum [Member]
Fair Value Inputs Assets Quantitative Information [Line Items]
Fair value inputs, combined transportation rate assumption	6.00%	[1]
Fair value inputs, forecasted interest rate on debt to be refinanced	5.00%
Fair value inputs, discount rate	8.00%
Equity Method Investments [Member] | Discounted Cash Flow Valuation Technique [Member] | Level 3 | One Hundred Percent [Member] | Maximum [Member]
Fair Value Inputs Assets Quantitative Information [Line Items]
Fair value inputs, future cash distributions	110.00%
Equity Method Investments [Member] | Discounted Cash Flow Valuation Technique [Member] | Level 3 | One Hundred Percent [Member] | Minimum [Member]
Fair Value Inputs Assets Quantitative Information [Line Items]
Fair value inputs, future cash distributions	90.00%

[1] Transportation rate beyond existing contract terms as a percentage of current mean REX rates.

XML

DERIVATIVE FINANCIAL INSTRUMENTS 3 (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012		Dec. 31, 2011
Fixed Price Contracts And Other Derivatives, Current Assets [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate instruments designated as hedging instruments	$ 6	[1],[2]	$ 5	[1],[2]
Total derivatives designated as hedging instruments	6	[1]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]
Interest rate and foreign exchange instruments	8	[1]
Interest rate interest rate instruments not designated as hedging instruments			8	[1]
Commodity contracts not subject to rate recovery not designated as hedging instruments	119	[1]	156	[1]
Associated offsetting commodity contracts not subject to rate recovery	(111)	[1]	(120)	[1]
Derivative commodity contracts subject to rate recovery not designated as hedging instruments	9	[1]	28	[1]
Associated offsetting commodity contracts subject to rate recovery	(5)	[1]	(10)	[1]
Total derivatives not designated as hedging instruments	20	[1]	62	[1]
Fixed Price Contracts And Other Derivatives, Current Assets [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]
Derivative commodity contracts subject to rate recovery not designated as hedging instruments	7	[1]	22	[1]
Associated offsetting commodity contracts subject to rate recovery	(4)	[1]	(5)	[1]
Total derivatives not designated as hedging instruments	3	[1]	17	[1]
Fixed Price Contracts And Other Derivatives, Current Assets [Member] | Southern California Gas Company [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]
Derivative commodity contracts subject to rate recovery not designated as hedging instruments	2	[1]	6	[1]
Associated offsetting commodity contracts subject to rate recovery	(1)	[1]	(5)	[1]
Total derivatives not designated as hedging instruments	1	[1]	1	[1]
Fixed Price Contracts And Other Derivatives, Noncurrent Assets [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate instruments designated as hedging instruments	15	[2]	11	[2]
Total derivatives designated as hedging instruments	15
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]
Interest rate and foreign exchange instruments	43
Interest rate interest rate instruments not designated as hedging instruments			41
Commodity contracts not subject to rate recovery not designated as hedging instruments	19		72
Associated offsetting commodity contracts not subject to rate recovery	(15)		(68)
Derivative commodity contracts subject to rate recovery not designated as hedging instruments	20		8
Associated offsetting commodity contracts subject to rate recovery	(1)		(2)
Total derivatives not designated as hedging instruments	66		51
Fixed Price Contracts And Other Derivatives, Noncurrent Assets [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]
Derivative commodity contracts subject to rate recovery not designated as hedging instruments	20		8
Associated offsetting commodity contracts subject to rate recovery	(1)		(2)
Total derivatives not designated as hedging instruments	19		6
Fixed Price Contracts And Other Derivatives, Current Liabilities [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate instruments designated as hedging instruments	(20)	[2],[3]	(17)	[2],[3]
Derivative commodity contracts not subject to rate recovery designated as hedging instruments	(3)	[3]
Total derivatives designated as hedging instruments	(23)	[3]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]
Interest rate and foreign exchange instruments	(8)	[3]
Interest rate interest rate instruments not designated as hedging instruments			(7)	[3]
Commodity contracts not subject to rate recovery not designated as hedging instruments	(131)	[3]	(148)	[3]
Associated offsetting commodity contracts not subject to rate recovery	111	[3]	120	[3]
Derivative commodity contracts subject to rate recovery not designated as hedging instruments	(39)	[3]	(62)	[3]
Associated offsetting commodity contracts subject to rate recovery	5	[3]	10	[3]
Total derivatives not designated as hedging instruments	(62)	[3]	(87)	[3]
Fixed Price Contracts And Other Derivatives, Current Liabilities [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate instruments designated as hedging instruments	(17)	[2],[3]	(16)	[2],[3]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]
Derivative commodity contracts subject to rate recovery not designated as hedging instruments	(37)	[3]	(55)	[3]
Associated offsetting commodity contracts subject to rate recovery	4	[3]	5	[3]
Total derivatives not designated as hedging instruments	(33)	[3]	(50)	[3]
Fixed Price Contracts And Other Derivatives, Current Liabilities [Member] | Southern California Gas Company [Member]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]
Derivative commodity contracts subject to rate recovery not designated as hedging instruments	(2)	[3]	(7)	[3]
Associated offsetting commodity contracts subject to rate recovery	1	[3]	5	[3]
Total derivatives not designated as hedging instruments	(1)	[3]	(2)	[3]
Fixed Price Contracts And Other Derivatives, Noncurrent Liabilities [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate instruments designated as hedging instruments	(69)	[2]	(65)	[2]
Total derivatives designated as hedging instruments	(69)
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]
Interest rate and foreign exchange instruments	(38)
Interest rate interest rate instruments not designated as hedging instruments			(36)
Commodity contracts not subject to rate recovery not designated as hedging instruments	(31)		(94)
Associated offsetting commodity contracts not subject to rate recovery	15		68
Derivative commodity contracts subject to rate recovery not designated as hedging instruments	(7)		(24)
Associated offsetting commodity contracts subject to rate recovery	1		2
Total derivatives not designated as hedging instruments	(60)		(84)
Fixed Price Contracts And Other Derivatives, Noncurrent Liabilities [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Derivative Instruments in Hedges, at Fair Value, Net [Abstract]
Interest rate instruments designated as hedging instruments	(68)	[2]	(65)	[2]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net, Total [Abstract]
Derivative commodity contracts subject to rate recovery not designated as hedging instruments	(7)		(24)
Associated offsetting commodity contracts subject to rate recovery	1		2
Total derivatives not designated as hedging instruments	$ (6)		$ (22)

[1] Included in Current Assets: Other for SoCalGas.

[2] Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

[3] Included in Current Liabilities: Other for SoCalGas.

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OTHER FINANCIAL DATA - COMMON STOCK REPURCHASE PROGRAM (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010
Share Repurchases [Abstract]
Prepayment for shares to be repurchased under Collared Accelerated Share Acquisition Program			$ 500
Accelerated Share Repurchases, Initial Share Delivery			5,670,006
Accelerated Share Repurchases, Interim Share Delivery	1,496,435	2,407,994
Accelerated Share Repurchases, Total Share Delivery	9,574,435
Accelerated Share Repurchases Final Price Paid Per Share	$ 52.22

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COMMITMENTS AND CONTINGENCIES - LEGAL PROCEEDINGS (Details)								3 Months Ended		9 Months Ended		3 Months Ended		3 Months Ended
	Sep. 30, 2012 USD ($)	Dec. 31, 2011 USD ($)		Sep. 30, 2012 San Diego Gas and Electric Company and Subsidiary [Member] USD ($)	Dec. 31, 2011 San Diego Gas and Electric Company and Subsidiary [Member] USD ($)		Sep. 30, 2012 Southern California Gas Company [Member] USD ($)	Sep. 30, 2012 Loss from Catastrophes [Member] S D G E Segment [Member] USD ($)	Sep. 30, 2011 Loss from Catastrophes [Member] S D G E Segment [Member] USD ($)	Sep. 30, 2012 Loss from Catastrophes [Member] S D G E Segment [Member] USD ($)	Sep. 30, 2011 Loss from Catastrophes [Member] S D G E Segment [Member] USD ($)	Sep. 30, 2012 Loss from Catastrophes [Member] San Diego Gas and Electric Company and Subsidiary [Member] USD ($)	Sep. 30, 2012 Liberty Gas Storage Litigation [Member] USD ($)	Sep. 30, 2012 HMRC VAT Claim [Member] GBP (£)
Loss Contingencies [Line Items]
Loss Contingency Accrual, at Carrying Value	$ 427,000,000			$ 411,000,000			$ 5,000,000					$ 411,000,000
Payments for Legal Settlements												14,750,000
Claims Payments By Insurers To All Claimants												1,600,000,000
Percentage of Total Claims to be Paid by Company												57.50%
Total Individual And Business Claims												1,400,000,000
Liability Insurance Coverage, Maximum												1,100,000,000
Litigation Settlement, Gross												824,000,000
Loss Contingency Monetary Damages Sought													56,700,000
Estimated Gain Loss On Contract Termination													215,000,000
Payments For Legal Settlements In Excess Of Recovered Amounts												187,000,000
Loss Contingency Accrual Carrying Value, Current												284,000,000
Loss Contingency Accrual Carrying Value, Noncurrent												127,000,000
VAT Tax Claim Amount														86,000,000
Regulatory Assets Arising From Wildfire Litigation Costs	326,000,000	594,000,000	[1],[2]	326,000,000	594,000,000	[2]
Potential Impact On Earnings												175,000,000
Portion of Regulatory Assets Arising From Wildfire Litigation Related To CPUC Operations												292,000,000
Loss From Loss Contingencies [Line Items]
Loss Contingency, Loss in Period								$ (1,000,000)	$ 5,000,000	$ 4,000,000	$ 7,000,000

[1] As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

[2] Derived from audited financial statements.

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GENERAL (DETAILS) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended			3 Months Ended	6 Months Ended			3 Months Ended	6 Months Ended			3 Months Ended	6 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2008	Jun. 30, 2011 Change In Accounting Principle, As Originally Reported [Member]	Jun. 30, 2011 Change In Accounting Principle, As Originally Reported [Member]	Dec. 31, 2011 Change In Accounting Principle, As Originally Reported [Member]		Jun. 30, 2011 Change In Accounting Principle, Adjustments [Member]	Jun. 30, 2011 Change In Accounting Principle, Adjustments [Member]	Dec. 31, 2011 Change In Accounting Principle, Adjustments [Member]		Jun. 30, 2011 Change In Accounting Principle, Retrospectively Adjusted [Member]	Jun. 30, 2011 Change In Accounting Principle, Retrospectively Adjusted [Member]	Dec. 31, 2011 Change In Accounting Principle, Retrospectively Adjusted [Member]
Effect of Change in Accounting Principle [Line Items]
Change In Accounting Principle, Depreciation And Amortization					$ 730				$ (1)				$ 729
Change In Accounting Principle, Income Before Income Taxes And Equity Earnings Of Certain Unconsolidated Subsidiaries					1,316				1				1,317
Change In Accounting Principle, Income Tax Expense				68	269			7	20			75	289
Change In Accounting Principle, Net Income				326	1,092			(7)	(19)			319	1,073
Change In Accounting Principle, Earnings				296	1,065			(7)	(19)			289	1,046
Change In Accounting Principle, Basic Earnings Per Common Share				$ 1.23	$ 4.44			$ (0.02)	$ (0.08)			$ 1.21	$ 4.36
Change In Accounting Principle, Diluted Earnings Per Common Share				$ 1.22	$ 4.40			$ (0.02)	$ (0.08)			$ 1.20	$ 4.32
Change In Accounting Principle, Deferred Income Taxes And Invesment Tax Credits					224				(13)				211
Change In Accounting Principle, Net Change In Other Working Capital Components (Income Taxes)					(108)				33				(75)
Change In Accounting Principle, Income Taxes Payable						16				(11)				5
Change In Accounting Principle, Deferred Credits And Other						773				1				774
Change In Accounting Principle, Deferred Income Taxes, Noncurrent Liability						1,554				(34)				1,520
Change In Accounting Principle, Property Plant And Equipment						31,303				(111)				31,192
Change In Accounting Principle, Less Accumulated Depreciation And Amortization						7,731				(4)				7,727
Change In Accounting Principle Property Plant And Equipment Net						23,572				(107)				23,465
Change In Accounting Principle, Retained Earnings						8,225	[1]			(63)	[1]			8,162	[1]
Cumulative Effect of Change in Accounting Principle [Abstract]
Cumulative Effect of Change In Accounting Principle Of Reductions In Net Income And Earnings	26	30	7
Retained Earnings Cumulative Effect Of Change In Accounting Principle Net Of Tax		$ 37

[1] Adjustment includes the cumulative effect of the change in accounting principle of reductions in net income and earnings of $26 million, $30 million, a negligible amount, and $7 million for the years ended December 31, 2011, 2010, 2009 and 2008, respectively.

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FAIR VALUE MEASUREMENTS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011	Sep. 30, 2012		Sep. 30, 2011	Dec. 31, 2011
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 585			$ 585			$ 562
Gross unrealized gains	311			311			248
Gross unrealized losses	(4)			(4)			(6)
Estimated fair value	892			892			804
Proceeds from sales	204		294	524		384
Gross realized gains	3		27	12		29
Gross realized losses	(1)		(8)	(6)		(10)
Total Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost	308			308			305
Gross unrealized gains	27			27			21
Gross unrealized losses							(1)
Estimated fair value	335			335			325
Debt Securities Issued By The U.S. Treasury And Other U.S. Government Corporations And Agencies
Schedule of Available-for-sale Securities [Line Items]
Cost	134	[1]		134	[1]		157
Gross unrealized gains	12	[1]		12	[1]		13
Estimated fair value	146	[1]		146	[1]		170
Municipal Bonds
Schedule of Available-for-sale Securities [Line Items]
Cost	60	[2]		60	[2]		72
Gross unrealized gains	6	[2]		6	[2]		5
Estimated fair value	66	[2]		66	[2]		77
Other Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost	114	[3]		114	[3]		76
Gross unrealized gains	9	[3]		9	[3]		3
Gross unrealized losses							(1)
Estimated fair value	123	[3]		123	[3]		78
Equity Securities
Schedule of Available-for-sale Securities [Line Items]
Cost	249			249			246
Gross unrealized gains	284			284			227
Gross unrealized losses	(4)			(4)			(5)
Estimated fair value	529			529			468
Cash And Cash Equivalents
Schedule of Available-for-sale Securities [Line Items]
Cost	28			28			11
Estimated fair value	$ 28			$ 28			$ 11

[1] Maturity dates are 2013-2042

[2] Maturity dates are 2012-2057

[3] Maturity dates are 2013-2111

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DEBT AND CREDIT FACILITIES (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Line Of Credit Facility, Sempra Energy Consolidated [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	$ 4,100
Committed lines of credit, remaining borrowing capacity	3,500
Weighted average interest rate on total short-term debt outstanding	0.82%	0.93%
Line Of Credit Facility, Sempra Energy [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	1,067
Committed lines of credit, maximum ratio of indebtedness to total capitalization	65.00%
Committed lines of credit, capacity for issuance of letters of credit	700
Other instruments supported by committed lines of credit	47
Line Of Credit Facility, Sempra Global [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	2,189
Committed lines of credit, maximum ratio of indebtedness to total capitalization	65.00%
Outstanding commercial paper supported by committed lines of credit	545
Commercial paper noncurrent		400
Line Of Credit Facility, S D G E [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	658
Committed lines of credit, maximum ratio of indebtedness to total capitalization	65.00%
Committed lines of credit, remaining borrowing capacity	656
Outstanding commercial paper supported by committed lines of credit	2
Weighted average interest rate on total short-term debt outstanding	0.20%
Line Of Credit Facility, So Cal Gas [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	658
Committed lines of credit, maximum ratio of indebtedness to total capitalization	65.00%
Committed lines of credit, remaining borrowing capacity	658
Line Of Credit Facility, California Utilities Combined [Member]
Line of Credit Facility [Line Items]
Committed lines of credit, maximum borrowing capacity	877
Committed lines of credit, capacity for issuance of letters of credit	$ 200

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OTHER FINANCIAL DATA - COMPREHENSIVE INCOME AND EQUITY (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011		Dec. 31, 2011
Comprehensive Income And Equity Disclosure [Line Items]
Equity, beginning of period					$ 10,178	[1],[2]	$ 9,201
Comprehensive income, net of income tax
Net income	290		319	[1]	615		1,073	[1]
Foreign currency translation adjustments	88		(139)	[1]	125		(110)	[1]
Reclassification to net income of foreign currency translation adjustments related to equity method investments							(54)	[1],[3]
Financial instruments	(7)		(39)	[1]	(22)		(52)	[1]
Net actuarial gain	(10)		1	[1]	(5)		8	[1]
Purchase of noncontrolling interest in subsidiary							(43)
Share-based compensation expense					33		36
Common stock dividends declared					(435)		(346)
Preferred dividends of subsidiaries	(2)		(1)	[1]	(5)		(6)	[1]
Issuance of common stock					50		22
Tax benefit related to share-based compensation							6
Repurchases of common stock					(16)		(18)
Acquisition of South American entities							279
Redemption of preferred stock of subidiary							(80)
Common stock released from ESOP					9		15
Equity contributed by noncontrolling interests					5		6
Distributions to noncontrolling interests					(36)		(9)
Equity, end of period	10,496		9,928		10,496		9,928
Other Comprehensive Income (Loss), Tax [Abstract]
Financial instruments, income tax expense (benefit)	(1)		(11)		(5)		(11)
Foreign currency translation adjustments			(1)				(1)
Net actuarial gain, income tax expense (benefit)	(7)		1		(4)		5
Ownership Interests Held By Others [Line Items]
Amount of ownership interests held by others	394				394				383
Ownership Interests Held By Others, Bay Gas Storage Company [Member]
Ownership Interests Held By Others [Line Items]
Percent of ownership held by others	9.00%	[4]			9.00%	[4]
Amount of ownership interests held by others	19	[4]			19	[4]			17	[4]
Ownership Interests Held By Others, Southern Gas Transmission [Member]
Ownership Interests Held By Others [Line Items]
Percent of ownership held by others	49.00%	[4]			49.00%	[4]
Amount of ownership interests held by others	1	[4]			1	[4]			1	[4]
Ownership Interests Held By Others, Liberty Gas Storage [Member]
Ownership Interests Held By Others [Line Items]
Percent of ownership held by others	25.00%	[4]			25.00%	[4]
Amount of ownership interests held by others	13	[4]			13	[4]			9	[4]
Ownership Interests Held By Others, Tecsur [Member]
Ownership Interests Held By Others [Line Items]
Percent of ownership held by others	10.00%				10.00%
Amount of ownership interests held by others	4				4				4
Ownership Interests Held By Others, Luz Del Sur [Member]
Ownership Interests Held By Others [Line Items]
Percent of ownership held by others	20.00%				20.00%
Amount of ownership interests held by others	230				230				216
Ownership Interests Held By Others, Chilquinta Energia [Member]
Ownership Interests Held By Others [Line Items]
Percent of ownership held by others, minimum	15.00%				15.00%
Percent of ownership held by others, maximum	43.00%				43.00%
Amount of ownership interests held by others	37				37				34
Ownership Interests Held By Others, Otay Mesa VIE [Member]
Ownership Interests Held By Others [Line Items]
Percent of ownership held by others	100.00%				100.00%
Amount of ownership interests held by others	90				90				102
San Diego Gas and Electric Company and Subsidiary [Member]
Comprehensive Income And Equity Disclosure [Line Items]
Equity, beginning of period					3,841	[2]	3,221
Comprehensive income, net of income tax
Net income	188		136		401		283
Financial instruments	(4)		(25)		(13)		(34)
Net actuarial gain			1				1
Preferred dividend requirements	(2)		(2)		(4)		(4)
Capital contribution			200				200
Equity contributed by noncontrolling interests							6
Distributions to noncontrolling interests					(22)
Equity, end of period	4,203		3,673		4,203		3,673
Southern California Gas Company [Member]
Comprehensive Income And Equity Disclosure [Line Items]
Equity, beginning of period					2,193
Comprehensive income, net of income tax
Net income	71		81		191		209
Financial instruments			1		1		2
Preferred dividend requirements	0		0		(1)		(1)
Equity, end of period	2,234				2,234
Other Comprehensive Income (Loss), Tax [Abstract]
Financial instruments, income tax expense (benefit)	1				1		1
Total Shareholders' Equity
Comprehensive Income And Equity Disclosure [Line Items]
Equity, beginning of period					9,775		8,990
Comprehensive income, net of income tax
Net income	270		290	[1]	571		1,052	[1]
Foreign currency translation adjustments	80		(132)	[1]	114		(109)	[1]
Reclassification to net income of foreign currency translation adjustments related to equity method investments							(54)	[1],[3]
Financial instruments	(3)		(14)	[1]	(9)		(18)	[1]
Net actuarial gain	(10)		1	[1]	(5)		8	[1]
Purchase of noncontrolling interest in subsidiary							(4)
Share-based compensation expense					33		36
Common stock dividends declared					(435)		(346)
Preferred dividends of subsidiaries	(2)		(1)	[1]	(5)		(6)	[1]
Issuance of common stock					50		22
Tax benefit related to share-based compensation							6
Repurchases of common stock					(16)		(18)
Common stock released from ESOP					9		15
Equity, end of period	10,082		9,574		10,082		9,574
Other Comprehensive Income (Loss), Tax [Abstract]
Financial instruments, income tax expense (benefit)	(1)	[5]	(11)	[5]	(5)	[5]	(11)	[5]
Foreign currency translation adjustments			(1)	[5]			(1)	[5]
Net actuarial gain, income tax expense (benefit)	(7)	[5]	1	[5]	(4)	[5]	5	[5]
Total Shareholders' Equity | San Diego Gas and Electric Company and Subsidiary [Member]
Comprehensive Income And Equity Disclosure [Line Items]
Equity, beginning of period					3,739		3,108
Comprehensive income, net of income tax
Net income	176		115		378		277
Net actuarial gain			1				1
Preferred dividend requirements					(4)		(4)
Capital contribution			200				200
Equity, end of period	4,113		3,582		4,113		3,582
Total Shareholders' Equity | Southern California Gas Company [Member]
Other Comprehensive Income (Loss), Tax [Abstract]
Financial instruments, income tax expense (benefit)	1	[5]			1	[5]	1	[5]
Noncontrolling Interests
Comprehensive Income And Equity Disclosure [Line Items]
Equity, beginning of period					403		211
Comprehensive income, net of income tax
Net income	20		29	[1]	44		21	[1]
Foreign currency translation adjustments	8		(7)	[1]	11		(1)	[1]
Financial instruments	(4)		(25)	[1]	(13)		(34)	[1]
Purchase of noncontrolling interest in subsidiary							(39)
Acquisition of South American entities							279
Redemption of preferred stock of subidiary							(80)
Equity contributed by noncontrolling interests					5		6
Distributions to noncontrolling interests					(36)		(9)
Equity, end of period	414		354		414		354
Noncontrolling Interests | San Diego Gas and Electric Company and Subsidiary [Member]
Comprehensive Income And Equity Disclosure [Line Items]
Equity, beginning of period					102		113
Comprehensive income, net of income tax
Net income	12		21		23		6
Financial instruments	(4)		(25)		(13)		(34)
Equity contributed by noncontrolling interests							6
Distributions to noncontrolling interests					(22)
Equity, end of period	$ 90		$ 91		$ 90		$ 91

[1] As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

[2] Derived from audited financial statements.

[3] Related to the acquisition of Chilquinta Energía and Luz del Sur.

[4] Part of Sempra Natural Gas.

[5] Shareholders’ equity of Sempra Energy Consolidated or SoCalGas as indicated in left margin.

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FAIR VALUE MEASUREMENTS 3 (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012		Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - equity securities	$ 529		$ 468
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	146		170
Nuclear decomissioning trusts - Municipal debt securities	66		77
Nuclear decommissioning trusts - Other debt securities	123		78
Nuclear decommissioning trusts - Total debt securities	335		325
Total nuclear decommissioning trusts	864	[1]	793	[1]
Interest rate instruments, assets	73		66
Commodity contracts subject to rate recovery, assets	44		34
Commodity contracts not subject to rate recovery, assets	38		48
Investments	1		5
Total fair value of assets measured on a recurring basis	1,020		946
Interest rate instruments, liabilities	136		125
Commodity contracts subject to rate recovery, liabilities	8		13
Commodity contracts not subject to rate recovery, liabilities	26		49
Total fair value of liabilities measured on a recurring basis	170		187
San Diego Gas and Electric Company and Subsidiary [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - equity securities	529		468
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	146		170
Nuclear decomissioning trusts - Municipal debt securities	66		77
Nuclear decommissioning trusts - Other debt securities	123		78
Nuclear decommissioning trusts - Total debt securities	335		325
Total nuclear decommissioning trusts	864	[1]	793	[1]
Commodity contracts subject to rate recovery, assets	42		32
Commodity contracts not subject to rate recovery, assets	2		1
Total fair value of assets measured on a recurring basis	908		826
Interest rate instruments, liabilities	85		81
Commodity contracts subject to rate recovery, liabilities	7		12
Total fair value of liabilities measured on a recurring basis	92		93
Southern California Gas Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity contracts subject to rate recovery, assets	2		2
Commodity contracts not subject to rate recovery, assets	2		2
Total fair value of assets measured on a recurring basis	4		4
Commodity contracts subject to rate recovery, liabilities	1		1
Total fair value of liabilities measured on a recurring basis	1		1
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - equity securities	529		468
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	72		92
Nuclear decommissioning trusts - Total debt securities	72		92
Total nuclear decommissioning trusts	601	[1]	560	[1]
Commodity contracts subject to rate recovery, assets	21		10
Commodity contracts not subject to rate recovery, assets	19		15
Investments	1		5
Total fair value of assets measured on a recurring basis	642		590
Interest rate instruments, liabilities			1
Commodity contracts subject to rate recovery, liabilities	32		61
Commodity contracts not subject to rate recovery, liabilities	9		1
Total fair value of liabilities measured on a recurring basis	41		63
Level 1 | San Diego Gas and Electric Company and Subsidiary [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - equity securities	529		468
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	72		92
Nuclear decommissioning trusts - Total debt securities	72		92
Total nuclear decommissioning trusts	601	[1]	560	[1]
Commodity contracts subject to rate recovery, assets	19		9
Commodity contracts not subject to rate recovery, assets	2		1
Total fair value of assets measured on a recurring basis	622		570
Commodity contracts subject to rate recovery, liabilities	32		61
Total fair value of liabilities measured on a recurring basis	32		61
Level 1 | Southern California Gas Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity contracts subject to rate recovery, assets	2		1
Commodity contracts not subject to rate recovery, assets	2		2
Total fair value of assets measured on a recurring basis	4		3
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	74		78
Nuclear decomissioning trusts - Municipal debt securities	66		77
Nuclear decommissioning trusts - Other debt securities	123		78
Nuclear decommissioning trusts - Total debt securities	263		233
Total nuclear decommissioning trusts	263	[1]	233	[1]
Interest rate instruments, assets	73		66
Commodity contracts subject to rate recovery, assets			1
Commodity contracts not subject to rate recovery, assets	19		35
Total fair value of assets measured on a recurring basis	355		335
Interest rate instruments, liabilities	136		124
Commodity contracts subject to rate recovery, liabilities	8		13
Commodity contracts not subject to rate recovery, liabilities	30		52
Total fair value of liabilities measured on a recurring basis	174		189
Level 2 | San Diego Gas and Electric Company and Subsidiary [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nuclear decommissioning trusts - Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	74		78
Nuclear decomissioning trusts - Municipal debt securities	66		77
Nuclear decommissioning trusts - Other debt securities	123		78
Nuclear decommissioning trusts - Total debt securities	263		233
Total nuclear decommissioning trusts	263	[1]	233	[1]
Total fair value of assets measured on a recurring basis	263		233
Interest rate instruments, liabilities	85		81
Commodity contracts subject to rate recovery, liabilities	7		12
Total fair value of liabilities measured on a recurring basis	92		93
Level 2 | Southern California Gas Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity contracts subject to rate recovery, assets			1
Total fair value of assets measured on a recurring basis			1
Commodity contracts subject to rate recovery, liabilities	1		1
Total fair value of liabilities measured on a recurring basis	1		1
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity contracts subject to rate recovery, assets	23		23
Total fair value of assets measured on a recurring basis	23		23
Level 3 | San Diego Gas and Electric Company and Subsidiary [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity contracts subject to rate recovery, assets	23		23
Total fair value of assets measured on a recurring basis	23		23
Collateral Netted [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity contracts not subject to rate recovery, assets			(2)
Total fair value of assets measured on a recurring basis			(2)
Commodity contracts subject to rate recovery, liabilities	(32)		(61)
Commodity contracts not subject to rate recovery, liabilities	(13)		(4)
Total fair value of liabilities measured on a recurring basis	(45)		(65)
Collateral Netted [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity contracts subject to rate recovery, liabilities	(32)		(61)
Total fair value of liabilities measured on a recurring basis	$ (32)		$ (61)

[1] Excludes cash balances and cash equivalents.

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DERIVATIVE FINANCIAL INSTRUMENTS 4 (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011
Cash Flow Hedges
Derivative Instruments, Gain (Loss) [Line Items]
Amount of pretax gain (loss) on derivative recognized in OCI (effective portion)	$ (15)		$ (48)		$ (36)		$ (66)
Gain (loss) reclassified from AOCI into earnings (effective portion)	(7)		2		(9)		(3)
Cash Flow Hedges | Interest Expense | Interest Rate Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Amount of pretax gain (loss) on derivative recognized in OCI (effective portion)	(6)	[1]	(21)	[1]	(21)	[1]	(32)	[1]
Gain (loss) reclassified from AOCI into earnings (effective portion)	(3)	[1]	4	[1]	(5)	[1]
Cash Flow Hedges | Interest Expense | Interest Rate Instruments | San Diego Gas and Electric Company and Subsidiary [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of pretax gain (loss) on derivative recognized in OCI (effective portion)	(6)	[1]	(21)	[1]	(16)	[1]	(32)	[1]
Gain (loss) reclassified from AOCI into earnings (effective portion)	(2)	[1]	4	[1]	(3)	[1]	2	[1]
Cash Flow Hedges | Interest Expense | Interest Rate Instruments | Southern California Gas Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from AOCI into earnings (effective portion)	(1)		(1)		(2)		(3)
Cash Flow Hedges | Equity Earnings Before Income Tax [Member] | Interest Rate Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Amount of pretax gain (loss) on derivative recognized in OCI (effective portion)	(6)		(27)		(12)		(34)
Gain (loss) reclassified from AOCI into earnings (effective portion)	(4)		(2)		(4)		(3)
Cash Flow Hedges | Cost of Natural Gas, Electric Fuel and Purchased Power [Member] | Commodity Contracts Not Subject To Rate Recovery
Derivative Instruments, Gain (Loss) [Line Items]
Amount of pretax gain (loss) on derivative recognized in OCI (effective portion)	(3)				(3)
Fair Value Hedges
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	5	[2]	15	[2]	11	[2]	23	[2]
Fair Value Hedges | Southern California Gas Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings							(2)	[2]
Fair Value Hedges | Interest Expense | Interest Rate Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	1		2		5		7
Fair Value Hedges | Interest Expense | Interest Rate Instruments | Southern California Gas Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings							1
Fair Value Hedges | Other Income, Net | Interest Rate Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	4		13		6		16
Fair Value Hedges | Other Income, Net | Interest Rate Instruments | Southern California Gas Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings							(3)
Undesignated Derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	38		(40)		40		(2)
Undesignated Derivatives | San Diego Gas and Electric Company and Subsidiary [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	41		(16)		32		(6)
Undesignated Derivatives | Southern California Gas Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	1		(3)				(1)
Undesignated Derivatives | Other Income, Net | Interest Rate And Foreign Exchange Instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	1		(26)		11		(14)
Undesignated Derivatives | Revenues: Energy-Related Businesses [Member] | Commodity Contracts Not Subject To Rate Recovery
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	(5)		3		(3)		17
Undesignated Derivatives | Cost of Natural Gas, Electric Fuel and Purchased Power [Member] | Commodity Contracts Not Subject To Rate Recovery
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings							1
Undesignated Derivatives | Cost of Electric Fuel and Purchased Power [Member] | Commodity Contracts Subject To Rate Recovery [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	41		(15)		32		(6)
Undesignated Derivatives | Cost of Electric Fuel and Purchased Power [Member] | Commodity Contracts Subject To Rate Recovery [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	41		(15)		32		(6)
Undesignated Derivatives | Other Operation And Maintenance [Member] | Commodity Contracts Not Subject To Rate Recovery
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	1				1		1
Undesignated Derivatives | Other Operation And Maintenance [Member] | Commodity Contracts Not Subject To Rate Recovery | San Diego Gas and Electric Company and Subsidiary [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings			(1)
Undesignated Derivatives | Other Operation And Maintenance [Member] | Commodity Contracts Not Subject To Rate Recovery | Southern California Gas Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings	1		(1)		1
Undesignated Derivatives | Cost of Natural Gas [Member] | Commodity Contracts Subject To Rate Recovery [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings			(2)		(1)		(1)
Undesignated Derivatives | Cost of Natural Gas [Member] | Commodity Contracts Subject To Rate Recovery [Member] | Southern California Gas Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative recognized in earnings			$ (2)		$ (1)		$ (1)

[1] Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. There has been a negligible amount of ineffectiveness related to these swaps.

[2] There has been no hedge ineffectiveness on these swaps. Changes in the fair values of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt.

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RECENT INVESTMENT ACTIVITY

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Recent Investment Activity

NOTE 3. ACQUISITION AND INVESTMENT ACTIVITY

We discuss our investments in unconsolidated entities in Note 4.

Sempra South American Utilities

Chilquinta Energía S.A. (Chilquinta Energía) and Luz del Sur S.A.A. (Luz del Sur)

On April 6, 2011, Sempra South American Utilities acquired from AEI its interests in Chilquinta Energía in Chile and Luz del Sur in Peru, and their subsidiaries. Prior to the acquisition, Sempra South American Utilities and AEI each owned 50 percent of Chilquinta Energía and approximately 38 percent of Luz del Sur and accounted for the investments under the equity method. Upon completion of the acquisition and a public tender offer to the minority shareholders of Luz del Sur, Sempra South American Utilities owned 100 percent of Chilquinta Energía and approximately 80 percent of Luz del Sur, with the remaining shares of Luz del Sur held by institutional investors and the general public. As part of the transaction, Sempra South American Utilities also acquired AEI's interests in two energy-services companies, Tecnored S.A. (Tecnored) and Tecsur S.A. (Tecsur). We provide additional information about Sempra South American Utilities' acquisition of Chilquinta Energía and Luz del Sur and the public tender offer in Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Our results for the nine months ended September 30, 2011 include a $277 million gain (both pretax and after-tax) related to the remeasurement of equity method investments, included as Remeasurement of Equity Method Investments on our Condensed Consolidated Statement of Operations. We discuss the calculation of the gain in Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Our Condensed Consolidated Statements of Operationsinclude 100 percent of the acquired companies' revenues, net income and earnings of $1.1 billion, $155 million and $135 million, respectively, for the nine months ended September 30, 2012, including revenues, net income, and earnings of $356 million, $56 million and $49 million, respectively, for the three months ended September 30, 2012. Net income and earnings include holding companies reported in Parent and Other.Revenues, net income and earnings from the date of acquisition were $706 million, $108 million and $92 million, respectively, forthe nine months ended September 30, 2011 and $345 million, $60 million and $52 million, respectively, for the three months ended September 30, 2011. These amounts do not include the remeasurement gain.

Following areproforma revenues and earnings for Sempra Energy had the acquisition occurred on January 1, 2010, which primarily reflect the changes to revenues and earnings from our increased ownership and consolidation of the entities acquired. Although some short-term debt borrowings may have resulted from the actual acquisition in 2011, we have not assumed any additional interest expense in the pro forma impact on earnings below, as the amounts would be immaterial due to the low interest rates available to us on commercial paper. The proforma amounts do not include the impact of the increased ownership in Luz del Sur resulting from the tender offer completed in September 2011 discussed above andin Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

		Three months ended		Nine months ended
(Dollars in millions)		September 30, 2011		September 30, 2011
Revenues		$	2,576	$	7,775
Earnings(1)			289		794	(2)
(1)	As adjusted for the retrospective effect of change in accounting principle as we discuss in Note 1.
(2)	Excludes the $277 million gain related to remeasurement of equity method investments.

Sempra Natural Gas

Willmut Gas Company

In May 2012, Sempra Natural Gas acquired 100 percent of the outstanding common stock of Willmut Gas Company (Willmut Gas), a regulated natural gas distribution utility serving approximately 20,000 customers in Hattiesburg, Mississippi, in order to expandSempra Natural Gas' service area in the Southeast United States. Willmut Gas was purchased for $19 million in cash and the assumption of $10 million of liabilities. Included in the acquisition was $17 million in net property, plant and equipment. As a result of the acquisition, we recorded $10 million of goodwill.

The results of operations for Willmut Gas are included in our Condensed Consolidated Statements of Operations and Cash Flows beginning from the date of acquisition and include revenues of $5 million and negligible earnings for the nine months ended September 30, 2012 and revenues of $3 million and negligible earnings for the three months ended September 30, 2012.

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DEBT AND CREDIT FACILITIES 2 (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012
Other Long Term Debt, Fixed Rate Due 2017 [Member] | Sempra Energy [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 600
Debt Instrument, Interest Rate, Stated Percentage	2.30%
Other Long Term Debt, Fixed Rate Due 2017 [Member] | Luz Del Sur [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	21
Debt Instrument, Interest Rate, Stated Percentage	5.97%
Other Long Term Debt, Fixed Rate Due 2042 [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	250
Debt Instrument, Interest Rate, Stated Percentage	4.30%
Other Long Term Debt, Fixed Rate Due 2042 [Member] | Southern California Gas Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	350
Debt Instrument, Interest Rate, Stated Percentage	3.75%
Other Long Term Debt, Floating Rate Due 2028 [Member] | Copper Mountain Solar I [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	117
Debt Instrument, Interest Rate, Stated Percentage	4.54%
Debt Instrument, Interest Rate At Period End	2.86%
Debt Instrument, Floating To Fixed Interest Rate Swap	88
Other Long Term Debt, Fixed Rate Due 2022 [Member] | Sempra Energy [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	500
Debt Instrument, Interest Rate, Stated Percentage	2.875%
Other Long Term Debt, Fixed Rate Due 2018 [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	161
Debt Instrument, Interest Rate, Stated Percentage	1.65%
Other Long Term Debt, Fixed Rate Due 2039 [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	75
Debt Instrument, Interest Rate, Stated Percentage	4.00%
Other Long Term Debt, Fixed Rate Due February 2019 [Member] | Luz Del Sur [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	9
Debt Instrument, Interest Rate, Stated Percentage	6.34%
Other Long Term Debt, Fixed Rate Due July 2019 [Member] | Luz Del Sur [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 25
Debt Instrument, Interest Rate, Stated Percentage	5.44%

XML

OTHER FINANCIAL DATA - VARIABLE INTEREST ENTITIES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Variable Interest Entities Disclosure [Abstract]
Secured debt of variable interest entity	$ 347		$ 347
Amounts Associated With Variable Interest Entities, Cost of Electric Fuel And Purchased Power	(26)	(29)	(66)	(55)
Amounts Associated With Variable Interest Entities, Operation And Maintenance	4	1	15	23
Amounts Associated With Variable Interest Entities, Depreciation And Amortization	7	7	19	20
Amounts Associated With Variable Interest Entities, Total Operating Expenses	(15)	(21)	(32)	(12)
Amounts Associated With Variable Interest Entities, Operating Income	15	21	32	12
Amounts Associated With Variable Interest Entities, Other Income (Expense), Net		4	(1)
Amounts Associated With Variable Interest Entities, Interest Expense	(3)	(4)	(8)	(6)
Amounts Associated With Variable Interest Entities, Net Income	12	21	23	6
Amounts Associated With Variable Interest Entities, (Earnings) Losses Attributable Noncontrolling Interests	$ (12)	$ (21)	$ (23)	$ (6)

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OTHER FINANCIAL DATA - U.S. Treasury Grants Receivable (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012
U S Treasury Grants Receivable Disclosure [Abstract]
U.S. Treasury grants receivable	$ 181

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CALIFORNIA UTILITIES' REGULATORY MATTERS (Details) (USD $)	3 Months Ended
	Sep. 30, 2012
San Diego Gas and Electric Company and Subsidiary [Member]
Schedule Of Regulatory Amounts [Line Items]
General Rate Case, Annual Revenue Requirement Increase	$ 235,000,000
General Rate Case, Percentage Annual Revenue Requirement Increase	14.60%
Regulatory Recovery, Deductible Per Event	5,000,000
Incremental insurance costs incurred related to catastrophe for 2009-2010 policy period	29,000,000
Incremental insurance costs incurred related to catastrophe for 2010-2011 policy period	63,000,000
General Rate Case, Revenue Requirement Request	1,849,000,000
Incremental Insurance Premiums Cost Recovery In GRC	67,000,000
Incremental Insurance Premiums Included In 2011 Earnings	28,000,000
Authorized Return On Equity	11.10%
Authorized Return On Rate Base	8.40%
Authorized Capital Structure, Common Equity	49.00%
Requested Return On Equity	11.00%
Requested Return On Rate Base	8.15%
Requested Capital Structure, Common Equity	52.00%
Nuclear Plant, Ownership Percentage	20.00%
Nuclear Plant, Proportional Investment	180,000,000
Nuclear Plant, Replacement Power Costs	54,000,000
Nuclear Plant, Rate Base Investment	220,000,000
Nuclear Plant, Net Book Investment	485,000,000
Nuclear Plant, MHI Limited Liability	137,000,000
Nuclear Plant, Revenue Recognized Associated with SONGS	153,000,000
Nuclear Plant, Invoice to MHI	45,000,000
Minimum Unrecoverable Per Wildfire	10,000,000
Southern California Gas Company [Member]
Schedule Of Regulatory Amounts [Line Items]
General Rate Case, Annual Revenue Requirement Increase	268,000,000
General Rate Case, Percentage Annual Revenue Requirement Increase	14.50%
Unrecorded Gas Cost Incentive Mechanism Award	5,400,000
General Rate Case, Revenue Requirement Request	2,112,000,000
Recognized Gas Cost Incentive Mechanism Award 2010-2011	6,200,000
Authorized Return On Equity	10.82%
Authorized Return On Rate Base	8.68%
Authorized Capital Structure, Common Equity	48.00%
Requested Return On Equity	10.90%
Requested Return On Rate Base	8.44%
Requested Capital Structure, Common Equity	52.00%
East County Substation [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost	435,000,000
South Orange County Reliability Enhancement [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost	473,000,000
Aliso Canyon Natural Gas Storage Compressor Replacement [Member] | Southern California Gas Company [Member]
Schedule Of Utility Projects [Line Items]
Estimated Project Cost	$ 200,000,000

XML

DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012		Dec. 31, 2011
S D G E Segment [Member]
Schedule Of Commodity Derivative Volumes [Line Items]
Commodity derivative volumes, natural gas (in millions of million British thermal units)	$ 23	[1]	$ 35	[1]
Commodity derivative volumes, congestion revenue rights (in millions of megawatt hours)	18	[2]	19	[2]
Sempra Mexico Segment [Member]
Schedule Of Commodity Derivative Volumes [Line Items]
Commodity derivative volumes, natural gas (in millions of million British thermal units)	1	[1]	1	[1]
Sempra Natural Gas Segment [Member]
Schedule Of Commodity Derivative Volumes [Line Items]
Commodity derivative volumes, natural gas (in millions of million British thermal units)	32	[1]	20	[1]
Commodity derivative volumes, electric power (in millions of megawatt hours)	$ 2	[2]	$ 5	[2]

[1] Million British thermal units

[2] Megawatt hours

XML

OTHER FINANCIAL DATA - GOODWILL (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012		Dec. 31, 2011
Goodwill by Segment, Sempra Energy Consolidated [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance			$ 1,036
Foreign currency translation	63	[1]
Acquisition of subsidiary	10
Goodwill, Ending Balance	1,109
Goodwill By Segment, Sempra South American Utilities [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance			949
Foreign currency translation	63	[1]
Goodwill, Ending Balance	1,012
Goodwill By Segment, Sempra Mexico [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance			25
Goodwill, Ending Balance	25
Goodwill By Segment, Sempra Natural Gas [Member]
Goodwill [Line Items]
Goodwill, Beginning Balance			62
Acquisition of subsidiary	10
Goodwill, Ending Balance	$ 72

[1] We record the offset of this fluctuation to other comprehensive income.

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OTHER FINANCIAL DATA - PENSION AND OTHER POSTRETIREMENT BENEFITS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Southern California Gas Company [Member]
Remeasurement Due To Collective Bargaining Agreement [Line Items]
Discount Rate For Remeasurement			4.65%
Decrease In Recorded Liability From Remeasurement			$ 66
Pension Benefits
Net Periodic Benefit Cost
Service cost	23	20	68	63
Interest cost	40	41	122	126
Expected return on assets	(38)	(36)	(116)	(109)
Amortization of prior service cost		1	2	3
Amortization of actuarial loss	12	8	35	26
Settlement	1	1	8	11
Regulatory adjustment	9	31	(9)	6
Total net periodic benefit cost	47	66	110	126
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to pension plans			111
Expected contributions to pension and other postretirement benefit plans	123		123
Pension Benefits | San Diego Gas and Electric Company and Subsidiary [Member]
Net Periodic Benefit Cost
Service cost	7	6	21	21
Interest cost	11	12	34	37
Expected return on assets	(11)	(10)	(35)	(35)
Amortization of prior service cost			1	1
Amortization of actuarial loss	4	2	11	7
Settlement	(1)		1	1
Regulatory adjustment	7	15	7	13
Total net periodic benefit cost	17	25	40	45
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to pension plans			36
Expected contributions to pension and other postretirement benefit plans	45		45
Pension Benefits | Southern California Gas Company [Member]
Net Periodic Benefit Cost
Service cost	13	10	40	34
Interest cost	24	24	74	74
Expected return on assets	(23)	(21)	(72)	(64)
Amortization of prior service cost		1	1	2
Amortization of actuarial loss	6	4	17	12
Settlement			1	1
Regulatory adjustment	2	16	(16)	(7)
Total net periodic benefit cost	22	34	45	52
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to pension plans			45
Expected contributions to pension and other postretirement benefit plans	47		47
Other Postretirement Benefits
Net Periodic Benefit Cost
Service cost	4	8	19	23
Interest cost	11	16	39	49
Expected return on assets	(13)	(12)	(40)	(36)
Amortization of prior service cost			(2)
Amortization of actuarial loss	2	4	9	13
Regulatory adjustment	3	2	8	6
Total net periodic benefit cost	7	18	33	55
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to other postretirement benefit plans			32
Expected contributions to pension and other postretirement benefit plans	41		41
Other Postretirement Benefits | San Diego Gas and Electric Company and Subsidiary [Member]
Net Periodic Benefit Cost
Service cost	1	1	5	5
Interest cost	2	2	6	7
Expected return on assets	(1)	(1)	(5)	(5)
Amortization of prior service cost	1	1	3	3
Regulatory adjustment	1	1	2	2
Total net periodic benefit cost	4	4	11	12
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to other postretirement benefit plans			10
Expected contributions to pension and other postretirement benefit plans	13		13
Other Postretirement Benefits | Southern California Gas Company [Member]
Net Periodic Benefit Cost
Service cost	2	7	12	17
Interest cost	9	12	31	39
Expected return on assets	(10)	(10)	(33)	(30)
Amortization of prior service cost	(1)	(1)	(5)	(3)
Amortization of actuarial loss	1	4	8	13
Regulatory adjustment	2	1	6	4
Total net periodic benefit cost	3	13	19	40
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions to other postretirement benefit plans			19
Expected contributions to pension and other postretirement benefit plans	$ 23		$ 23

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NEW ACCOUNTING STANDARDS

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

New Accounting Standards

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) 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRSs)” (ASU 2011-04): ASU 2011-04 amends Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures, and provides changes in the wording used to describe the requirements for measuring fair value and disclosing information about fair value measurement. ASU 2011-04 results in common fair value measurement and disclosure requirements under both GAAP and IFRSs.

ASU 2011-04 expands fair value measurement disclosures for Level 3 instruments to require

• quantitative information about the unobservable inputs
• a description of the valuation process
• a qualitative discussion about the sensitivity of the measurements

We adopted ASU 2011-04 on January 1, 2012and it did not affect our financial position, results of operations or cash flows. The required disclosure is provided in Note 8.

ASU 2011-05, “Presentation of Comprehensive Income” (ASU 2011-05) and ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (ASU 2011-12):ASU 2011-05 amends ASC Topic 220, Comprehensive Income, and eliminates the option to report other comprehensive income and its components in the statement of changes in equity. The ASU allows an entity an option to present the components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements.

ASU 2011-05 does not change the items that must be reported in other comprehensive income, when an item of other comprehensive income must be reclassified to net income, or the earnings per share computation.

ASU 2011-12 defers the requirement to separately present on the face of the statement of operations or statement of comprehensive income reclassification adjustments for items that are reclassified from other comprehensive income to net income.

We adopted ASU 2011-05 on January 1, 2012 and have elected to present the components of net income and other comprehensive income in two separate, but consecutive, statements for all periods presented.

ASU 2011-11, “Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11): In order to allow for balance sheet comparison between GAAP and IFRSs, ASU 2011-11 requires enhanced disclosures related to financial assets and liabilities eligible for offsetting in the statement of financial position. An entity will have to disclose both gross and net information about financial instruments and transactions subject to a master netting arrangement and eligible for offset, including cash collateral received and posted.

We will adopt ASU 2011-11 on January 1, 2013 as required and do not expect it to affect our financial position, results of operations or cash flows. We will provide the additional disclosure in our 2013 interim financial statements.

ASU 2012-02, “Testing Indefinite-Lived Intangible Assets for Impairment” (ASU 2012-02): ASU 2012-02 amends ASC Topic 350, Intangibles – Goodwill and Others, to provide an option to first make a qualitative assessment of whether it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount before applying the quantitative impairment test.  An entity is required to perform the quantitative test only if it determines that it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount.

We will adopt ASU 2012-02 for our annual impairment testing as of October 1, 2012 and do not expect it to significantly affect our financial statements.

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OTHER FINANCIAL DATA - EARNINGS PER SHARE (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012	Sep. 30, 2011
Earnings Per Share Numerator [Abstract]
Earnings	$ 268		$ 289	[1]	$ 566	$ 1,046	[1]
Earnings Per Share Denominator [Abstract]
Weighted-average common shares outstanding for basic EPS	241,689,000		239,545,000	[1]	241,133,000	239,693,000	[1]
Dilutive effect of stock options, restricted stock awards and restricted stock units	4,113,000		2,335,000	[1]	3,880,000	2,262,000	[1]
Weighted-average common shares outstanding for diluted EPS	245,802,000		241,880,000	[1]	245,013,000	241,955,000	[1]
Earnings Per Share [Abstract]
Basic earnings per common share	$ 1.11		$ 1.21	[1]	$ 2.35	$ 4.36	[1]
Diluted earnings per common share	$ 1.09		$ 1.20	[1]	$ 2.31	$ 4.32	[1]
Seventy Fifth Percentile Or Above [Member]
Total Shareholder Return Ranking [Line Items]
Common Shares Received For Each Restricted Stock Unit	1.5	[2]
Fiftieth Percentile [Member]
Total Shareholder Return Ranking [Line Items]
Common Shares Received For Each Restricted Stock Unit	1	[2]
Thirty Fifth Percentile Or Below [Member]
Total Shareholder Return Ranking [Line Items]
Common Shares Received For Each Restricted Stock Unit	0	[2]
Restricted Stock Units [Member]
Schedule Of Performance Based Restricted Shares [Line Items]
Contractual vesting percentage maximum	150.00%
Restricted Stock Awards [Member]
Schedule Of Performance Based Restricted Shares [Line Items]
Contractual vesting percentage maximum	100.00%
Out Of The Money Stock Options [Member]
Antidilutive Securities Excluded From Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share			2,112,880		40,000	2,111,839
In The Money Stock Options
Antidilutive Securities Excluded From Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share						900
Restricted Stock
Antidilutive Securities Excluded From Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	2,349,338		3,473,578		2,523,343	3,630,253
Restricted Stock Units
Antidilutive Securities Excluded From Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	3,387		1,109		1,881
Restricted Stock Awards [Member]
Antidilutive Securities Excluded From Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share					14,319
San Diego Gas and Electric Company and Subsidiary [Member]
Earnings Per Share Numerator [Abstract]
Earnings	176		115		378	277
Southern California Gas Company [Member]
Earnings Per Share Numerator [Abstract]
Earnings	$ 71		$ 81		$ 191	$ 209

[1] As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

[2] (2) Participants may also receive additional shares for dividend equivalents on units subject to restricted stock units, which are reinvested to purchase additional units that become subject to the same vesting conditions as the restricted stock units to which the dividends relate.

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OTHER FINANCIAL DATA - INCOME TAXES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011		Sep. 30, 2012	Sep. 30, 2011
Income Tax Expense And Effective Income Tax Rates Disclosure [Line Items]
Income tax expense (benefit)	$ 49	$ 75	[1]	$ 48	$ 289	[1]
Effective income tax rate	15.00%	19.00%		8.00%	22.00%
Remeasurement of equity method investments					277	[1]
Income tax benefit associated with life insurance contracts				54
Income tax benefit for repair allowance	38			38
Income tax benefit for repair allowance related to 2011	22			22
San Diego Gas and Electric Company and Subsidiary [Member]
Income Tax Expense And Effective Income Tax Rates Disclosure [Line Items]
Income tax expense (benefit)	38	63		151	154
Effective income tax rate	17.00%	32.00%		27.00%	35.00%
Income tax benefit for repair allowance	38			38
Income tax benefit for repair allowance related to 2011	22			22
Southern California Gas Company [Member]
Income Tax Expense And Effective Income Tax Rates Disclosure [Line Items]
Income tax expense (benefit)	$ 37	$ 41		$ 105	$ 106
Effective income tax rate	34.00%	34.00%		35.00%	34.00%

[1] As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

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FAIR VALUE MEASUREMENTS 4 (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$ 13	$ 3	$ 23	$ 2
Realized and unrealized gains (losses)	16	5	23	17
Allocated transmission instruments	17		18	2
Settlements	(23)	(5)	(41)	(18)
Balance at end of period	23	3	23	3
CRR Auction Rate Per MWh, Minimum	(3)		(3)
CRR Auction Rate Per MWh, Maximum	$ 5		$ 5

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 530	$ 252	[1],[2]
Restricted cash	42	24	[1],[2]
Other accounts and notes receivable	152	147	[1],[2]
Trade accounts receivable	922	1,198	[1],[2]
Inventories	398	346	[1],[2]
Income taxes receivable	18
Regulatory balancing accounts, undercollected	301	38	[1],[2]
Regulatory assets	88	89	[1],[2]
Fixed-price contracts and other derivatives, current assets	74	85	[1],[2]
Settlement receivable related to wildfire litigation	180	10	[1],[2]
U.S. Treasury grants receivable	181
Other current assets	192	143	[1],[2]
Total current assets	3,078	2,332	[1],[2]
Investments And Other Assets [Abstract]
Restricted cash, noncurrent	20	22	[1],[2]
Regulatory assets arising from pension and other postretirement benefit obligations	1,027	1,126	[1],[2]
Regulatory assets arising from wildfire litigation costs	326	594	[1],[2]
Other regulatory assets	1,155	1,060	[1],[2]
Nuclear decommissioning trusts	892	804	[1],[2]
Other investments	1,585	1,671	[1],[2]
Goodwill	1,109	1,036	[1],[2]
Other intangible assets	441	448	[1],[2]
Sundry	767	691	[1],[2]
Total investments and other assets	7,322	7,452	[1],[2]
Property, plant and equipment:
Property, plant and equipment	33,251	31,192	[1],[2]
Less accumulated depreciation and amortization	(8,261)	(7,727)	[1],[2]
Property, plant and equipment, net	24,990	23,465	[1],[2]
Total assets	35,390	33,249	[1],[2]
Current liabilities:
Short-term debt	584	449	[1],[2]
Accounts payable - trade	970	983	[1],[2]
Accounts payable - other	126	124	[1],[2]
Income taxes payable		5	[1],[2]
Deferred income taxes, net current liabilities	155	173	[1],[2]
Dividends and interest payable	309	219	[1],[2]
Accrued compensation and benefits	273	323	[1],[2]
Regulatory balancing accounts, overcollected	117	105	[1],[2]
Current portion of long-term debt	709	336	[1],[2]
Fixed-price contracts and other derivatives, current liabilities	82	92	[1],[2]
Customer deposits	150	142	[1],[2]
Reserve for wildfire litigation (Note 10)	284	586	[1],[2]
Other current liabilities	590	615	[1],[2]
Total current liabilities	4,349	4,152	[1],[2]
Long-term debt	11,193	10,078	[1],[2]
Deferred Credits And Other Liabilities [Abstract]
Customer advances for construction	146	142	[1],[2]
Pension and other postretirement benefit obligations, net of plan assets	1,337	1,423	[1],[2]
Deferred income taxes, net noncurrent liabilities	1,609	1,520	[1],[2]
Deferred investment tax credits	47	49	[1],[2]
Regulatory liabilities arising from removal obligations	2,673	2,551	[1],[2]
Asset retirement obligations	1,981	1,905	[1],[2]
Other regulatory liabilities	55	87	[1],[2]
Noncurrent reserve for wildfire litigation (Note 10)	127	10	[1],[2]
Fixed-price contracts and other derivatives, noncurrent liabilities	270	301	[1],[2]
Deferred credits and other	1,028	774	[1],[2]
Total deferred credits and other liabilities	9,273	8,762	[1],[2]
Contingently redeemable preferred stock of subsidiary	79	79	[1],[2]
Equity:
Common stock	2,178	2,104	[1],[2]
Retained earnings	8,293	8,162	[1],[2]
Deferred compensation		(2)	[1],[2]
Accumulated other comprehensive income (loss)	(389)	(489)	[1],[2]
Total shareholders' equity	10,082	9,775	[1],[2]
Preferred stock of subsidiaries	20	20	[1],[2]
Other noncontrolling interests	394	383	[1],[2]
Total equity	10,496	10,178	[1],[2]
Total liabilities and equity	35,390	33,249	[1],[2]
San Diego Gas and Electric Company and Subsidiary [Member]
Current assets:
Cash and cash equivalents	22	29	[2]
Restricted cash	11	21	[2]
Other accounts and notes receivable	20	23	[2]
Trade accounts receivable	294	267	[2]
Inventories	83	82	[2]
Due from unconsolidated affiliates	17	67	[2]
Income taxes receivable	171	102	[2]
Regulatory balancing accounts, net	301	38	[2]
Regulatory assets arising from fixed-price contracts and other derivatives - current	63	67	[2]
Regulatory assets	11	11	[2]
Fixed-price contracts and other derivatives, current assets	25	27	[2]
Settlement receivable related to wildfire litigation	180	10	[2]
Other current assets	109	51	[2]
Total current assets	1,307	795	[2]
Investments And Other Assets [Abstract]
Restricted cash, noncurrent	20	22	[2]
Deferred taxes recoverable in rates	647	570	[2]
Regulatory assets arising from fixed-price contracts and other derivatives - noncurrent	138	191	[2]
Regulatory assets arising from pension and other postretirement benefit obligations	287	309	[2]
Regulatory assets arising from wildfire litigation costs	326	594	[2]
Other regulatory assets	252	160	[2]
Nuclear decommissioning trusts	892	804	[2]
Sundry	89	70	[2]
Total investments and other assets	2,651	2,720	[2]
Property, plant and equipment:
Property, plant and equipment	13,827	13,003	[2]
Less accumulated depreciation and amortization	(3,196)	(2,963)	[2]
Property, plant and equipment, net	10,631	10,040	[2]
Total assets	14,589	13,555	[2]
Current liabilities:
Short-term debt	2
Accounts payable - trade	304	375	[2]
Due to unconsolidated affiliates	20	14	[2]
Deferred income taxes, net current liabilities	54	62	[2]
Dividends and interest payable	55	32	[2]
Accrued compensation and benefits	93	124	[2]
Current portion of long-term debt	19	19	[2]
Fixed-price contracts and other derivatives, current liabilities	54	55	[2]
Customer deposits	63	62	[2]
Reserve for wildfire litigation (Note 10)	284	586	[2]
Other current liabilities	117	107	[2]
Total current liabilities	1,065	1,436	[2]
Long-term debt	4,293	4,058	[2]
Deferred Credits And Other Liabilities [Abstract]
Customer advances for construction	18	20	[2]
Pension and other postretirement benefit obligations, net of plan assets	323	342	[2]
Deferred income taxes, net noncurrent liabilities	1,515	1,167	[2]
Deferred investment tax credits	26	26	[2]
Regulatory liabilities arising from removal obligations	1,575	1,462	[2]
Asset retirement obligations	724	693	[2]
Noncurrent reserve for wildfire litigation (Note 10)	127	10	[2]
Fixed-price contracts and other derivatives, noncurrent liabilities	220	243	[2]
Deferred credits and other	421	178	[2]
Total deferred credits and other liabilities	4,949	4,141	[2]
Contingently redeemable preferred stock	79	79	[2]
Equity:
Common stock	1,338	1,338	[2]
Retained earnings	2,785	2,411	[2]
Accumulated other comprehensive income (loss)	(10)	(10)	[2]
Total shareholders' equity	4,113	3,739	[2]
Other noncontrolling interests	90	102	[2]
Total equity	4,203	3,841	[2]
Total liabilities and equity	14,589	13,555	[2]
Southern California Gas Company [Member]
Current assets:
Cash and cash equivalents	257	36	[2]
Other accounts and notes receivable	72	63	[2]
Trade accounts receivable	273	578	[2]
Inventories	166	151	[2]
Due from unconsolidated affiliates	280	40	[2]
Income taxes receivable	19	17	[2]
Regulatory assets	6	9	[2]
Other current assets	32	28	[2]
Total current assets	1,105	922	[2]
Investments And Other Assets [Abstract]
Regulatory assets arising from pension and other postretirement benefit obligations	730	808	[2]
Other regulatory assets	117	137	[2]
Sundry	11	8	[2]
Total investments and other assets	858	953	[2]
Property, plant and equipment:
Property, plant and equipment	10,919	10,565	[2]
Less accumulated depreciation and amortization	(4,098)	(3,965)	[2]
Property, plant and equipment, net	6,821	6,600	[2]
Total assets	8,784	8,475	[2]
Current liabilities:
Accounts payable - trade	254	315	[2]
Accounts payable - other	78	78	[2]
Due to unconsolidated affiliates	16	2	[2]
Deferred income taxes, net current liabilities	42	44	[2]
Accrued compensation and benefits	102	99	[2]
Regulatory balancing accounts, net credit	117	105	[2]
Current portion of long-term debt	254	257	[2]
Customer deposits	76	75	[2]
Other current liabilities	129	172	[2]
Total current liabilities	1,068	1,147	[2]
Long-term debt	1,409	1,064	[2]
Deferred Credits And Other Liabilities [Abstract]
Customer advances for construction	113	110	[2]
Pension and other postretirement benefit obligations, net of plan assets	756	833	[2]
Deferred income taxes, net noncurrent liabilities	652	576	[2]
Deferred investment tax credits	21	23	[2]
Regulatory liabilities arising from removal obligations	1,084	1,075	[2]
Asset retirement obligations	1,197	1,161	[2]
Deferred taxes refundable in rates	55	87	[2]
Deferred credits and other	195	206	[2]
Total deferred credits and other liabilities	4,073	4,071	[2]
Equity:
Preferred stock	22	22	[2]
Common stock	866	866	[2]
Retained earnings	1,366	1,326	[2]
Accumulated other comprehensive income (loss)	(20)	(21)	[2]
Total shareholders' equity	2,234	2,193	[2]
Total equity	2,234	2,193
Total liabilities and equity	$ 8,784	$ 8,475	[2]

[1] As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

[2] Derived from audited financial statements.

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DERIVATIVE FINANCIAL INSTRUMENTS 2 (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Sep. 30, 2012		Dec. 31, 2011
Schedule Of Notional Amounts Of Interest Rate Derivatives [Line Items]
Notional amount of interest rate derivatives, minimum	$ 6	[1]	$ 15	[1]
Notional amount of interest rate derivatives, maximum	369	[1]	305	[1]
Maturities of interest rate derivatives, minimum	2013	[1]	2013	[1]
Maturities of interest rate derivatives, maximum	2028	[1]	2019	[1]
San Diego Gas and Electric Company and Subsidiary [Member]
Schedule Of Notional Amounts Of Interest Rate Derivatives [Line Items]
Notional amount of interest rate derivatives, minimum	285	[1]	285	[1]
Notional amount of interest rate derivatives, maximum	$ 347	[1]	$ 355	[1]
Maturities of interest rate derivatives	2019	[1]	2019	[1]

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 615		$ 1,073	[1]
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	803		729	[1]
Deferred income taxes and investment tax credits	(45)		211	[1]
Remeasurement of equity method investments			(277)	[1]
Equity earnings	346		(41)	[1]
Fixed-price contracts and other derivatives	1		(7)	[1]
Other	(8)		(43)	[1]
Net change in other working capital components	(373)		(75)	[1]
Distributions from RBS Sempra Commodities LLP, operating activities			53	[1]
Changes in other assets	202		31	[1]
Changes in other liabilities	147		(11)	[1]
Net cash provided by operating activities	1,688		1,643	[1]
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(2,241)		(2,031)	[1]
Expeditures for investments and acquisition of businesses, net of cash acquired	(359)		(696)	[1]
Proceeds from sale of joint venture	9
Distributions from RBS Sempra Commodities LLP, investing activities			374	[1]
Distributions from investments	43		47	[1]
Purchases of nuclear decommissioning and other trust assets	(534)		(399)	[1]
Proceeds from sales by nuclear decommissioning and other trusts	534		398	[1]
Decrease in restricted cash	89		473	[1]
Increase in restricted cash	(105)		(450)	[1]
Other cash flows from investing activities	(12)		(20)	[1]
Net cash used in investing activities	(2,576)		(2,304)	[1]
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	(405)		(325)	[1]
Preferred dividends paid by subsidiaries	(5)		(6)	[1]
Issuances of common stock	50		22	[1]
Repurchases of common stock	(16)		(18)	[1]
Redemption of subsidiary preferred stock			(80)	[1]
Issuances of debt (maturities greater than 90 days)	2,294		1,525	[1]
Payments on debt (maturities greater than 90 days)	(563)		(366)	[1]
Increase (decrease) in short-term debt, net	(142)		(300)	[1]
Distributions to noncontrolling interests	(36)		(10)	[1]
Purchase of noncontrolling interests			(43)	[1]
Other cash flows from financing activities	(20)		5	[1]
Net cash provided by (used in) financing activities	1,157		404	[1]
Effect of exchange rate changes on cash and cash equivalents	9		2	[1]
Increase (decrease) in cash and cash equivalents	278		(255)	[1]
Cash and cash equivalents, beginning of period	252	[1],[2]	912	[1]
Cash and cash equivalents, end of period	530		657	[1]
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	278		281
Income tax payments, net of refunds	99		106
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	315		306
U. S. Treasury grants receivable	136	[3]
Cash grants previously recorded as investment tax credits	45
Acquisition Of Business [Abstract]
Assets acquired	29		2,831
Cash paid, net of cash acquired	(19)		(611)
Fair of equity method investments immediately prior to the acquisition			(882)
Fair value of noncontrolling interests			(279)
Additional consideration accrued			(32)
Liabilities Assumed	10		1,027
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
Dividends declared but not paid	149		119
San Diego Gas and Electric Company and Subsidiary [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	401		283
Adjustments to reconcile net income to net cash provided by operating activities:
Utility depreciation and amortization	359		316
Deferred income taxes and investment tax credits	262		226
Fixed-price contracts and other derivatives	(9)		(13)
Other	(55)		(43)
Net change in other working capital components	(518)		18
Changes in other assets	201		32
Changes in other liabilities	129
Net cash provided by operating activities	770		819
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(998)		(1,162)
Purchases of nuclear decommissioning and other trust assets	(530)		(395)
Proceeds from sales by nuclear decommissioning and other trusts	524		389
Decrease in restricted cash	74		340
Increase in restricted cash	(62)		(355)
Net cash used in investing activities	(992)		(1,183)
CASH FLOWS FROM FINANCING ACTIVITIES
Capital contribution			200
Preferred dividends paid	(4)		(4)
Issuances of long-term debt	249		348
Payments on long-term debt	(7)		(7)
Increase (decrease) in short-term debt, net	2
Contributions from noncontrolling interests			5
Distributions to noncontrolling interests	(22)
Other cash flows from financing activities	(3)		(2)
Net cash provided by (used in) financing activities	215		540
Increase (decrease) in cash and cash equivalents	(7)		176
Cash and cash equivalents, beginning of period	29	[2]	127
Cash and cash equivalents, end of period	22		303
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	96		80
Income tax payments, net of refunds	(121)		59
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	87		161
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
Dividends declared but not paid	1		1
Southern California Gas Company [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	191		209
Adjustments to reconcile net income to net cash provided by operating activities:
Utility depreciation and amortization	268		246
Deferred income taxes and investment tax credits	39		79
Other	(9)		(4)
Net change in other working capital components	240		(46)
Changes in other assets	4		17
Changes in other liabilities	13		(6)
Net cash provided by operating activities	746		495
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(462)		(499)
Increase (decrease) in loans to affiliates, net	(257)		(96)
Net cash used in investing activities	(719)		(595)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	(150)		(50)
Preferred dividends paid	(1)		(1)
Issuances of long-term debt	348
Payments on long-term debt			(250)
Debt issuances costs	(3)
Net cash provided by (used in) financing activities	194		(301)
Increase (decrease) in cash and cash equivalents	221		(401)
Cash and cash equivalents, beginning of period	36	[2]	417
Cash and cash equivalents, end of period	257		16
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	36		39
Income tax payments, net of refunds	46		17
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	$ 69		$ 81

[1] As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

[2] Derived from audited financial statements.

[3] Cash grants, excluding $45 million previously recorded in 2011 as investment tax credits.

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COMMITMENTS AND CONTINGENCIES - CONTRACTUAL COMMITMENTS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Sep. 30, 2012
Luz Del Sur [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Purchased Power Commitments, Payments Due, Current	$ (291)
Increase (Decrease) In Purchased Power Commitments, Payments Due In Two Years	15
Increase (Decrease) In Purchased Power Commitments, Payments Due In Three Years	2
Increase (Decrease) In Purchased Power Commitments, Payments Due In Four Years	(1)
Increase (Decrease) In Purchased Power Commitments, Payments Due In Five Years	8
Increase (Decrease) In Purchased Power Commitments, Payments Due Thereafter	105
Chilquinta Energia [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Purchased Power Commitments, Payments Due, Current	(205)
Increase (Decrease) In Purchased Power Commitments, Payments Due In Two Years	28
Increase (Decrease) In Purchased Power Commitments, Payments Due In Three Years	32
Increase (Decrease) In Purchased Power Commitments, Payments Due In Four Years	34
Increase (Decrease) In Purchased Power Commitments, Payments Due In Five Years	34
Increase (Decrease) In Purchased Power Commitments, Payments Due Thereafter	335
San Diego Gas and Electric Company and Subsidiary [Member]
Payments Under Contractual Commitments [Line Items]
Contractual Commitments, Payments Due, Current	62
Contractual Commitments, Payments Due In Two Years	159
Contractual Commitments, Payments Due In Three Years	20
Increase (Decrease) In Purchased Power Commitments, Payments Due, Current	(47)
Increase (Decrease) In Purchased Power Commitments, Payments Due In Two Years	18
Increase (Decrease) In Purchased Power Commitments, Payments Due In Three Years	61
Increase (Decrease) In Purchased Power Commitments, Payments Due In Four Years	66
Increase (Decrease) In Purchased Power Commitments, Payments Due In Five Years	67
Increase (Decrease) In Purchased Power Commitments, Payments Due Thereafter	1,400
Increase (Decrease) In Purchase Commitment Amount	1,600
Southern California Gas Company [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Natural Gas Contracts Commitments	232
Decrease In Natural Gas Contracts Commitments, Fulfillment	359
Increase In Natural Gas Contracts Commitments, New Contracts	591
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due, Current	(231)
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Two Years	307
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Three Years	67
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Four Years	34
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Five Years	4
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due Thereafter	51
Sempra South American Utilities [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Purchase Commitment Amount	96
Sempra Mexico [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Natural Gas Contracts Commitments	(128)
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due, Current	(81)
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Two Years	(22)
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Three Years	(25)
Sempra Natural Gas [Member]
Payments Under Contractual Commitments [Line Items]
Increase (Decrease) In Liquefied Natural Gas Commitments, Payments Due, Current	(384)
Increase (Decrease) In Liquefied Natural Gas Commitments, Payments Due In Two Years	(9)
Increase (Decrease) In Liquefied Natural Gas Commitments, Payments Due In Three Years	(18)
Increase (Decrease) In Liquefied Natural Gas Commitments, Payments Due In Four Years	(27)
Increase (Decrease) In Liquefied Natural Gas Commitments, Payments Due In Five Years	(33)
Increase (Decrease) In Liquefied Natural Gas Commitments, Payments Due Thereafter	(523)
Increase (Decrease) In Natural Gas Contracts Commitments	73
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due, Current	(7)
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Two Years	14
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Three Years	10
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Four Years	11
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due In Five Years	11
Increase (Decrease) In Natural Gas Contracts Commitments, Payments Due Thereafter	34
Sempra Renewables [Member]
Operating Leases [Line Items]
Operating Leases, Future Minimum Payments, Due in Two Years	2
Operating Leases, Future Minimum Payments, Due in Three Years	2
Operating Leases, Future Minimum Payments, Due in Four Years	2
Operating Leases, Future Minimum Payments, Due in Five Years	2
Operating Leases, Future Minimum Payments, Due Thereafter	57
Sunrise Powerlink Construction [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Long-term Purchase Commitment [Line Items]
Contractual Commitment Annual Escalation Percentage	2.00%
Contractual Commitment Number of Years	58
Contractual Commitment Future Annual Payment Amount	3
Contractual Commitment Present Value Future Payments, Regulatory Asset	116
Contractual Commitment Future Payments, Liability	113
Natural Gas Infrastructure Construction [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	11
Natural Gas Infrastructure Construction [Member] | Southern California Gas Company [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	60
Electric Distribution And Generation Plant [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	34
ECO Substation [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	196
Citizens Sunrise Transmission [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Long-term Purchase Commitment [Line Items]
Contractual Commitment Number of Years	30
Proceeds From Long Term Transmission Agreement	$ 85

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OTHER FINANCIAL DATA - SHARE-BASED COMPENSATION (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Share-based compensation expense, net of income taxes	$ 5	$ 7	$ 18	$ 20
Restricted stock units granted			927,734
Restricted stock awards granted			18,487

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DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Sep. 30, 2012

Derivative Financial Instruments (Tables) [Abstract]

Commodity Derivative Volumes Table

Segment and Commodity		September 30, 2012	December 31, 2011
California Utilities:
SDG&E:
Natural gas		23 million MMBtu	35 million MMBtu	(1)
Congestion revenue rights		18 million MWh	19 million MWh	(2)
Energy-Related Businesses:
Sempra Natural Gas:
Electric power		2 million MWh	5 million MWh
Natural gas		32 million MMBtu	20 million MMBtu
Sempra Mexico - natural gas		1 million MMBtu	1 million MMBtu
(1)	Million British thermal units
(2)	Megawatt hours

Notional Amounts of Interest Rate Derivatives Table

		September 30, 2012			December 31, 2011
(Dollars in millions)		Notional Debt		Maturities	Notional Debt		Maturities
Sempra Energy Consolidated(1)		$	6-369	2013-2028	$	15-305	2013-2019
SDG&E(1)			285-347	2019		285-355	2019
(1)	Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.

Derivative Instruments on the Condensed Consolidated Balance Sheets Table

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30, 2012
									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 designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Interest rate instruments(3)		$	6	$	15	$	(20)	$	(69)
Commodity contracts not subject to rate recovery			―		―		(3)		―
Total		$	6	$	15	$	(23)	$	(69)
SDG&E:
Interest rate instruments(3)		$	―	$	―	$	(17)	$	(68)
Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments		$	8	$	43	$	(8)	$	(38)
Commodity contracts not subject to rate recovery			119		19		(131)		(31)
Associated offsetting commodity contracts			(111)		(15)		111		15
Commodity contracts subject to rate recovery			9		20		(39)		(7)
Associated offsetting commodity contracts			(5)		(1)		5		1
Total		$	20	$	66	$	(62)	$	(60)
SDG&E:
Commodity contracts subject to rate recovery		$	7	$	20	$	(37)	$	(7)
Associated offsetting commodity contracts			(4)		(1)		4		1
Total		$	3	$	19	$	(33)	$	(6)
SoCalGas:
Commodity contracts subject to rate recovery		$	2	$	―	$	(2)	$	―
Associated offsetting commodity contracts			(1)		―		1		―
Total		$	1	$	―	$	(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.
DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		December 31, 2011
									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 designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Interest rate instruments(3)		$	5	$	11	$	(17)	$	(65)
SDG&E:
Interest rate instruments(3)		$	―	$	―	$	(16)	$	(65)
Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
Interest rate instruments		$	8	$	41	$	(7)	$	(36)
Commodity contracts not subject to rate recovery			156		72		(148)		(94)
Associated offsetting commodity contracts			(120)		(68)		120		68
Commodity contracts subject to rate recovery			28		8		(62)		(24)
Associated offsetting commodity contracts			(10)		(2)		10		2
Total		$	62	$	51	$	(87)	$	(84)
SDG&E:
Commodity contracts subject to rate recovery		$	22	$	8	$	(55)	$	(24)
Associated offsetting commodity contracts			(5)		(2)		5		2
Total		$	17	$	6	$	(50)	$	(22)
SoCalGas:
Commodity contracts subject to rate recovery		$	6	$	―	$	(7)	$	―
Associated offsetting commodity contracts			(5)		―		5		―
Total		$	1	$	―	$	(2)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

Fair Value Hedge Impact on the Condensed Consolidated Statements of Operations Table

FAIR VALUE HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
			Gain on derivatives recognized in earnings				Gain (loss) on derivatives recognized in earnings
			Three months ended September 30,				Nine months ended September 30,
		Location	2012		2011		2012		2011
Sempra Energy Consolidated:
Interest rate instruments		Interest Expense	$	1	$	2	$	5	$	7
Interest rate instruments		Other Income, Net		4		13		6		16
Total(1)			$	5	$	15	$	11	$	23
SoCalGas:
Interest rate instrument		Interest Expense	$	―	$	―	$	―	$	1
Interest rate instrument		Other Income, Net		―		―		―		(3)
Total(1)			$	―	$	―	$	―	$	(2)
(1)	There has been no hedge ineffectiveness on these swaps. Changes in the fair values of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt.

Cash Flow Hedge Impact on the Condensed Consolidated Statements of Operations Table

CASH FLOW HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
		Pretax loss recognized					Gain (loss) reclassified from AOCI
		in OCI (effective portion)					into earnings (effective portion)
		Three months ended September 30,					Three months ended September 30,
		2012		2011		Location	2012		2011
Sempra Energy Consolidated:
Interest rate instruments(1)		$	(6)	$	(21)	Interest Expense	$	(3)	$	4
						Equity Losses,
Interest rate instruments			(6)		(27)	Before Income Tax		(4)		(2)
Commodity contracts not subject						Cost of Natural Gas, Electric
to rate recovery			(3)		―	Fuel and Purchased Power		―		―
Total		$	(15)	$	(48)		$	(7)	$	2
SDG&E:
Interest rate instruments(1)		$	(6)	$	(21)	Interest Expense	$	(2)	$	4
SoCalGas:
Interest rate instruments		$	―	$	―	Interest Expense	$	(1)	$	(1)
		Nine months ended September 30,					Nine months ended September 30,
		2012		2011		Location	2012		2011
Sempra Energy Consolidated:
Interest rate instruments(1)		$	(21)	$	(32)	Interest Expense	$	(5)	$	―
						Equity Losses,
Interest rate instruments			(12)		(34)	Before Income Tax		(4)		(3)
Commodity contracts not subject						Cost of Natural Gas, Electric
to rate recovery			(3)		―	Fuel and Purchased Power		―		―
Total		$	(36)	$	(66)		$	(9)	$	(3)
SDG&E:
Interest rate instruments(1)		$	(16)	$	(32)	Interest Expense	$	(3)	$	2
SoCalGas:
Interest rate instruments		$	―	$	―	Interest Expense	$	(2)	$	(3)
(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. There has been a negligible amount of ineffectiveness related to these swaps.

Undesignated Derivative Impact on the Condensed Consolidated Statements of Operations Table

UNDESIGNATED DERIVATIVE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
		Gain (loss) on derivatives recognized in earnings
		Three months ended September 30,				Nine months ended September 30,
	Location	2012		2011		2012		2011
Sempra Energy Consolidated:
Interest rate and foreign exchange
instruments	Other Income, Net	$	1	$	(26)	$	11	$	(14)
Commodity contracts not subject	Revenues: Energy-Related
to rate recovery	Businesses		(5)		3		(3)		17
Commodity contracts not subject	Cost of Natural Gas, Electric
to rate recovery	Fuel and Purchased Power		―		―		―		1
Commodity contracts not subject
to rate recovery	Operation and Maintenance		1		―		1		1
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power		41		(15)		32		(6)
Commodity contracts subject
to rate recovery	Cost of Natural Gas		―		(2)		(1)		(1)
Total		$	38	$	(40)	$	40	$	(2)
SDG&E:
Commodity contracts not subject
to rate recovery	Operation and Maintenance	$	―	$	(1)	$	―	$	―
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power		41		(15)		32		(6)
Total		$	41	$	(16)	$	32	$	(6)
SoCalGas:
Commodity contracts not subject
to rate recovery	Operation and Maintenance	$	1	$	(1)	$	1	$	―
Commodity contracts subject
to rate recovery	Cost of Natural Gas		―		(2)		(1)		(1)
Total		$	1	$	(3)	$	―	$	(1)

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OTHER FINANCIAL DATA - CAPITALIZED FINANCING COSTS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Capitalized Financing Costs Disclosure [Line Items]
AFUDC related to debt	$ 5	$ 10	$ 32	$ 27
AFUDC related to equiity	13	26	80	67
Other capitalized financing costs	13	6	40	20
Total capitalized financing costs	31	42	152	114
San Diego Gas and Electric Company and Subsidiary [Member]
Capitalized Financing Costs Disclosure [Line Items]
AFUDC related to debt	3	8	26	22
AFUDC related to equiity	6	21	61	54
Total capitalized financing costs	9	29	87	76
Southern California Gas Company [Member]
Capitalized Financing Costs Disclosure [Line Items]
AFUDC related to debt	2	2	6	5
AFUDC related to equiity	7	5	19	13
Total capitalized financing costs	$ 9	$ 7	$ 25	$ 18

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SEGMENT INFORMATION (Tables)

3 Months Ended

Sep. 30, 2012

Segment Information (Tables) [Abstract]

Segment Information Table

SEGMENT INFORMATION
(Dollars in millions)
	Three months ended September 30,								Nine months ended September 30,
	2012				2011				2012				2011
REVENUES
SDG&E	$	1,092	44	%	$	868	34	%	$	2,706	39	%	$	2,405	32	%
SoCalGas		728	29			844	33			2,328	33			2,776	37
Sempra South American Utilities		356	14			345	13			1,061	15			706	10
Sempra Mexico		181	7			183	7			434	6			561	8
Sempra Renewables		27	1			7	―			49	1			17	―
Sempra Natural Gas		294	12			455	18			761	11			1,340	18
Adjustments and eliminations		―	―			(1)	―			(1)	―			(1)	―
Intersegment revenues(1)		(171)	(7)			(125)	(5)			(359)	(5)			(372)	(5)
Total	$	2,507	100	%	$	2,576	100	%	$	6,979	100	%	$	7,432	100	%
INTEREST EXPENSE
SDG&E	$	49			$	37			$	124			$	104
SoCalGas		17				17				51				52
Sempra South American Utilities		6				9				22				23
Sempra Mexico		4				4				10				15
Sempra Renewables		6				4				13				9
Sempra Natural Gas		26				22				72				62
All other		62				58				185				174
Intercompany eliminations		(44)				(33)				(125)				(95)
Total	$	126			$	118			$	352			$	344
INTEREST INCOME
SoCalGas	$	―			$	1			$	―			$	1
Sempra South American Utilities		3				6				11				18
Sempra Mexico		4				3				10				7
Sempra Renewables		2				―				3				―
Sempra Natural Gas		15				8				41				25
All other		―				(2)				―				1
Intercompany eliminations		(19)				(10)				(51)				(31)
Total	$	5			$	6			$	14			$	21
DEPRECIATION AND AMORTIZATION
SDG&E	$	128	46	%	$	108	43	%	$	359	45	%	$	316	43	%
SoCalGas		91	33			83	33			268	33			246	34
Sempra South American Utilities		15	5			14	6			42	5			27	4
Sempra Mexico		15	5			15	6			46	6			46	6
Sempra Renewables		4	1			1	―			10	1			4	1
Sempra Natural Gas		24	9			26	10			69	9			79	11
All other		3	1			4	2			9	1			11	1
Total	$	280	100	%	$	251	100	%	$	803	100	%	$	729	100	%
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	38			$	63			$	151			$	154
SoCalGas		37				41				105				106
Sempra South American Utilities		27				18				57				30
Sempra Mexico		21				(7)				44				24
Sempra Renewables		(12)				(9)				(47)				(22)
Sempra Natural Gas		(45)				27				(171)				97
All other		(17)				(58)				(91)				(100)
Total	$	49			$	75			$	48			$	289

SEGMENT INFORMATION (Continued)
(Dollars in millions)
		Three months ended September 30,								Nine months ended September 30,
		2012				2011				2012				2011
EQUITY EARNINGS (LOSSES)
Earnings (losses) recorded before tax:
Sempra Renewables		$	(6)			$	(6)			$	(7)			$	(6)
Sempra Natural Gas			(87)				10				(366)				29
All other			(1)				(16)				(2)				(27)
Total		$	(94)			$	(12)			$	(375)			$	(4)
Earnings recorded net of tax:
Sempra South American Utilities		$	―			$	―			$	―			$	23
Sempra Mexico			10				6				29				22
Total		$	10			$	6			$	29			$	45
EARNINGS (LOSSES)
SDG&E(2)		$	174	65	%	$	113	39	%	$	374	66	%	$	273	26	%
SoCalGas(2)			71	26			81	28			190	34			208	20
Sempra South American Utilities			40	15			50	17			118	21			386	37
Sempra Mexico			54	20			47	16			134	24			121	12
Sempra Renewables			13	5			1	1			47	8			9	1
Sempra Natural Gas			(68)	(25)			41	14			(260)	(46)			151	14
All other			(16)	(6)			(44)	(15)			(37)	(7)			(102)	(10)
Total		$	268	100	%	$	289	100	%	$	566	100	%	$	1,046	100	%
										Nine months ended September 30,
											2012				2011
EXPENDITURES FOR PROPERTY PLANT & EQUIPMENT
SDG&E										$	998	44	%	$	1,162	57	%
SoCalGas											462	21			499	25
Sempra South American Utilities											117	5			63	3
Sempra Mexico											13	1			11	1
Sempra Renewables											564	25			124	6
Sempra Natural Gas											84	4			171	8
All other											3	―			1	―
Total										$	2,241	100	%	$	2,031	100	%
										September 30, 2012				December 31, 2011
ASSETS
SDG&E										$	14,589	41	%	$	13,555	41	%
SoCalGas											8,784	25			8,475	25
Sempra South American Utilities											3,241	9			2,981	9
Sempra Mexico											3,042	9			2,914	9
Sempra Renewables											2,412	7			1,210	4
Sempra Natural Gas											5,910	17			5,738	17
All other											520	1			538	2
Intersegment receivables(3)											(3,108)	(9)			(2,162)	(7)
Total										$	35,390	100	%	$	33,249	100	%
INVESTMENTS IN EQUITY METHOD INVESTEES
Sempra Mexico										$	333			$	302
Sempra Renewables											666				390
Sempra Natural Gas											369				800
All other											135				137
Total										$	1,503			$	1,629
(1)	Revenues for reportable segments include intersegment revenues of:
	$3 million, $17 million, $78 million and $73 million for the three months ended September 30, 2012; $6 million, $48 million, $161 million and $144 million for the nine months ended September 30, 2012; $2 million, $13 million, $48 million and $62 million for the three months ended September 30, 2011; and $5 million, $38 million, $157 million and $172 million for the nine months ended September 30, 2011 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.
(2)	After preferred dividends.
(3)	Assets for reportable segments include intersegment receivables of:
	$17 million, $280 million, $54 million, $643 million, $521 million, and $1.6 billion at September 30, 2012; and $67 million, $40 million, $52 million, $543 million, $263 million, and $1.2 billion at December 31, 2011 for SDG&E, SoCalGas, Sempra South American Utilities, Sempra Mexico, Sempra Renewables and Sempra Natural Gas, respectively.

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GENERAL

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

General

NOTE 1. GENERAL

PRINCIPLES OF CONSOLIDATION

2012 Business Segment Realignment

Effective January 1, 2012, management realigned some of the company's major subsidiaries to better fit its strategic direction and to enhance the management and integration of our assets. This realignment resulted in a change in reportable segments in 2012. In accordance with accounting principles generally accepted in the United States (GAAP), historical information for Sempra Energy has been restated in its Condensed Consolidated Financial Statements and these Notes to reflect the effect of this change. All discussions of our operating units and reportable segments in these Notes reflect the new segments and operating structure.

Sempra Energy

Sempra Energy's Condensed Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 holding company, and its consolidated subsidiaries and variable interest entities (VIEs). Sempra Energy's principal operating units are

• San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), which are separate,reportable segments;
• Sempra International, which includes our Sempra South American Utilities and Sempra Mexico reportable segments; and

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

We provide descriptions of each of our segments in Note 11.

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.

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 subsidiaries in Note 4 herein and Note 4 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2011 and in our Current Report on Form 8-K filed on May 11, 2012, discussed below under “Basis of Presentation.”

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 subsidiaries, which comprise less than one percent of its consolidated financial position and results of operations. SoCalGas' common stock is wholly owned by Pacific Enterprises (PE), 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 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, 2012through the date thefinancial 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, 2011 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2011 consolidated financial statements. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the interim-period-reporting provisions of GAAP and the Securities and Exchange Commission.

You should read the information in this Quarterly Report in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2011 (the Annual Report)and our Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2012, which are combined reports for Sempra Energy, SDG&E and SoCalGas.You should also read the information in this Quarterly Report in conjunction with Sempra Energy's Current Report on Form 8-K and accompanying exhibits, filed on May 11, 2012, which updates the information in the Annual Report primarily for the change in reportable segments(discussed above) and change in accounting principle (discussed below) and which we refer to in this Quarterly Report as the Updated Annual Report. Although the Updated Annual Report contains the separate information for SDG&E and SoCalGas, as filed in the Annual Report, the Form 8-K did not provide updates to their information as separate registrants as they were not impacted by the change in reportable segments or change in accounting principle at Sempra Energy.

Sempra South American Utilities has controlling interests in two electric distribution utilities in South America. 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 Mexico, S de RL de CV (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 GAAP provisions governing regulated operations, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report. We follow the same accounting policies for interim reporting purposes, except for the adoption of new accounting standards as we discuss in Note 2.

Change in Accounting Principle

Effective January 1, 2012, we changed our method of accounting for investment tax credits (ITC) from the flow-through method to the deferral method for Sempra Energy. Under the flow-through method, we reduced our income tax expense by the amount of ITC in the year in which the qualifying assets were placed in service. Under the deferral method, we record ITC in the year when the qualifying assets are placed in service as a reduction to the cost of the asset that generated the ITC. This results in lower book depreciation over the life of the asset. This change has no historical or prospective impact on the California Utilities because ITC is effectively deferred as a result of the application of regulatory accounting required under GAAP.

The flow-through method and the deferral method are both acceptable under GAAP, but the deferral method is the preferred method. We believe that the deferral method is preferable for the ITC we receive because it recognizes ITC benefits over the same periods as the associated costs for which the ITC are intended to compensate.

We applied this change in accounting principle by retrospectively adjusting the historical financial statement amounts for all periods presented. Upon adopting the deferral method, we recorded an adjustment for the cumulative effect of the change in accounting principle to reduce Sempra Energy Consolidated retained earnings as of January 1, 2011 by $37 million.

For certain solar and wind generating assets being placed into service during 2011 and 2012, we have elected to seek cash grants rather than ITC for which the projects also qualify. Accordingly, cash grant accounting, which is similar to deferral accounting of ITC, is required to be applied. As a result, the impact of our change in accounting policy for ITC on our financial statements for the three months and nine months ending September 30, 2012 is insignificant. Cash grants are generally expected to be collectable in cash shortly after a project is constructed. Conversion of ITC to cash is generally dependent on reducing cash tax payments.

The following table summarizes the effects of the change in accounting principle on Sempra Energy'sCondensed Consolidated Financial Statements for the historical periods presented.

EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions, except per share amounts)
		Three months ended September 30, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
Income tax expense		$	68	$	7	$	75
Net income			326		(7)		319
Earnings			296		(7)		289
Basic earnings per common share		$	1.23	$	(0.02)	$	1.21
Diluted earnings per common share		$	1.22	$	(0.02)	$	1.20
		Nine months ended September 30, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
Depreciation and amortization		$	730	$	(1)	$	729
Income before income taxes and equity earnings
of certain unconsolidated subsidiaries			1,316		1		1,317
Income tax expense			269		20		289
Net income			1,092		(19)		1,073
Earnings			1,065		(19)		1,046
Basic earnings per common share		$	4.44	$	(0.08)	$	4.36
Diluted earnings per common share		$	4.40	$	(0.08)	$	4.32
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
Net income		$	1,092	$	(19)	$	1,073
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization			730		(1)		729
Deferred income taxes and investment tax credits			224		(13)		211
Net change in other working capital components (income taxes)			(108)		33		(75)
		As of December 31, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED BALANCE SHEET
Property, plant and equipment		$	31,303	$	(111)	$	31,192
Less accumulated depreciation and amortization			(7,731)		4		(7,727)
Property, plant and equipment, net		$	23,572	$	(107)	$	23,465
Income taxes payable		$	16	$	(11)	$	5
Deferred income taxes, noncurrent liability			1,554		(34)		1,520
Deferred credits and other			773		1		774
Retained earnings(1)			8,225		(63)		8,162
(1)	Adjustment includes the cumulative effect of the change in accounting principle of reductions in net income and earnings of $26 million, $30 million, a negligible amount, and $7 million for the years ended December 31, 2011, 2010, 2009 and 2008, respectively.

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parentheticals) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Property, plant and equipment related to VIE	$ 473	$ 494
Long-term debt related to VIE	337	345
Shareholders' equity:
Preferred stock, shares authorized	50	50
Common stock, shares authorized	750	750
Common stock, shares outstanding	242	240
San Diego Gas and Electric Company and Subsidiary [Member]
Property, plant and equipment related to VIE	473	494
Long-term debt related to VIE	$ 337	$ 345
Shareholders' equity:
Common stock, shares authorized	255	255
Common stock, shares outstanding	117	117
Southern California Gas Company [Member]
Shareholders' equity:
Common stock, shares authorized	100	100
Common stock, shares outstanding	91	91

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SEGMENT INFORMATION

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Segment Information

NOTE 11. SEGMENT INFORMATION

We have six separately managed reportable segments, as follows:

• SDG&E provides electric service to San Diego and southern Orange counties and natural gas service to San DiegoCounty.
• SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California.
• Sempra South American Utilities operates electric transmission and distribution utilities in Chile and Peru, and owns interests in utilities in Argentina. We are currently pursuing the sale of our interests in the Argentine utilities, which we discuss further in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
• Sempra Mexicodevelops,owns and operates, or holds interests in, natural gas transmission pipelines and propane systems, a natural gas distribution utility, electric generation facilities, including wind, and a terminal for the import of LNG and sale of natural gas in Mexico.
• Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy projects in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Nevada and Pennsylvania to serve wholesale electricity markets in the United States.
• Sempra Natural Gas develops, owns and operates, or holds interests in, a natural gas-fired electric generation plant, 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 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.

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 and the former commodities-marketing businesses.

SEGMENT INFORMATION
(Dollars in millions)
	Three months ended September 30,								Nine months ended September 30,
	2012				2011				2012				2011
REVENUES
SDG&E	$	1,092	44	%	$	868	34	%	$	2,706	39	%	$	2,405	32	%
SoCalGas		728	29			844	33			2,328	33			2,776	37
Sempra South American Utilities		356	14			345	13			1,061	15			706	10
Sempra Mexico		181	7			183	7			434	6			561	8
Sempra Renewables		27	1			7	―			49	1			17	―
Sempra Natural Gas		294	12			455	18			761	11			1,340	18
Adjustments and eliminations		―	―			(1)	―			(1)	―			(1)	―
Intersegment revenues(1)		(171)	(7)			(125)	(5)			(359)	(5)			(372)	(5)
Total	$	2,507	100	%	$	2,576	100	%	$	6,979	100	%	$	7,432	100	%
INTEREST EXPENSE
SDG&E	$	49			$	37			$	124			$	104
SoCalGas		17				17				51				52
Sempra South American Utilities		6				9				22				23
Sempra Mexico		4				4				10				15
Sempra Renewables		6				4				13				9
Sempra Natural Gas		26				22				72				62
All other		62				58				185				174
Intercompany eliminations		(44)				(33)				(125)				(95)
Total	$	126			$	118			$	352			$	344
INTEREST INCOME
SoCalGas	$	―			$	1			$	―			$	1
Sempra South American Utilities		3				6				11				18
Sempra Mexico		4				3				10				7
Sempra Renewables		2				―				3				―
Sempra Natural Gas		15				8				41				25
All other		―				(2)				―				1
Intercompany eliminations		(19)				(10)				(51)				(31)
Total	$	5			$	6			$	14			$	21
DEPRECIATION AND AMORTIZATION
SDG&E	$	128	46	%	$	108	43	%	$	359	45	%	$	316	43	%
SoCalGas		91	33			83	33			268	33			246	34
Sempra South American Utilities		15	5			14	6			42	5			27	4
Sempra Mexico		15	5			15	6			46	6			46	6
Sempra Renewables		4	1			1	―			10	1			4	1
Sempra Natural Gas		24	9			26	10			69	9			79	11
All other		3	1			4	2			9	1			11	1
Total	$	280	100	%	$	251	100	%	$	803	100	%	$	729	100	%
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	38			$	63			$	151			$	154
SoCalGas		37				41				105				106
Sempra South American Utilities		27				18				57				30
Sempra Mexico		21				(7)				44				24
Sempra Renewables		(12)				(9)				(47)				(22)
Sempra Natural Gas		(45)				27				(171)				97
All other		(17)				(58)				(91)				(100)
Total	$	49			$	75			$	48			$	289

SEGMENT INFORMATION (Continued)
(Dollars in millions)
		Three months ended September 30,								Nine months ended September 30,
		2012				2011				2012				2011
EQUITY EARNINGS (LOSSES)
Earnings (losses) recorded before tax:
Sempra Renewables		$	(6)			$	(6)			$	(7)			$	(6)
Sempra Natural Gas			(87)				10				(366)				29
All other			(1)				(16)				(2)				(27)
Total		$	(94)			$	(12)			$	(375)			$	(4)
Earnings recorded net of tax:
Sempra South American Utilities		$	―			$	―			$	―			$	23
Sempra Mexico			10				6				29				22
Total		$	10			$	6			$	29			$	45
EARNINGS (LOSSES)
SDG&E(2)		$	174	65	%	$	113	39	%	$	374	66	%	$	273	26	%
SoCalGas(2)			71	26			81	28			190	34			208	20
Sempra South American Utilities			40	15			50	17			118	21			386	37
Sempra Mexico			54	20			47	16			134	24			121	12
Sempra Renewables			13	5			1	1			47	8			9	1
Sempra Natural Gas			(68)	(25)			41	14			(260)	(46)			151	14
All other			(16)	(6)			(44)	(15)			(37)	(7)			(102)	(10)
Total		$	268	100	%	$	289	100	%	$	566	100	%	$	1,046	100	%
										Nine months ended September 30,
											2012				2011
EXPENDITURES FOR PROPERTY PLANT & EQUIPMENT
SDG&E										$	998	44	%	$	1,162	57	%
SoCalGas											462	21			499	25
Sempra South American Utilities											117	5			63	3
Sempra Mexico											13	1			11	1
Sempra Renewables											564	25			124	6
Sempra Natural Gas											84	4			171	8
All other											3	―			1	―
Total										$	2,241	100	%	$	2,031	100	%
										September 30, 2012				December 31, 2011
ASSETS
SDG&E										$	14,589	41	%	$	13,555	41	%
SoCalGas											8,784	25			8,475	25
Sempra South American Utilities											3,241	9			2,981	9
Sempra Mexico											3,042	9			2,914	9
Sempra Renewables											2,412	7			1,210	4
Sempra Natural Gas											5,910	17			5,738	17
All other											520	1			538	2
Intersegment receivables(3)											(3,108)	(9)			(2,162)	(7)
Total										$	35,390	100	%	$	33,249	100	%
INVESTMENTS IN EQUITY METHOD INVESTEES
Sempra Mexico										$	333			$	302
Sempra Renewables											666				390
Sempra Natural Gas											369				800
All other											135				137
Total										$	1,503			$	1,629
(1)	Revenues for reportable segments include intersegment revenues of:
	$3 million, $17 million, $78 million and $73 million for the three months ended September 30, 2012; $6 million, $48 million, $161 million and $144 million for the nine months ended September 30, 2012; $2 million, $13 million, $48 million and $62 million for the three months ended September 30, 2011; and $5 million, $38 million, $157 million and $172 million for the nine months ended September 30, 2011 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.
(2)	After preferred dividends.
(3)	Assets for reportable segments include intersegment receivables of:
	$17 million, $280 million, $54 million, $643 million, $521 million, and $1.6 billion at September 30, 2012; and $67 million, $40 million, $52 million, $543 million, $263 million, and $1.2 billion at December 31, 2011 for SDG&E, SoCalGas, Sempra South American Utilities, Sempra Mexico, Sempra Renewables and Sempra Natural Gas, respectively.

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DOCUMENT AND ENTITY INFORMATION	3 Months Ended
	Sep. 30, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	Sempra Energy
Document Type	10-Q
Document Period End Date	Sep. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Shares Outstanding	241,851,686
Entity Central Index Key	0001032208

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Sep. 30, 2012

Significant Accounting Policies

Investment Tax Credit Policy [Text Block]

Change in Accounting Principle

Effective January 1, 2012, we changed our method of accounting for investment tax credits (ITC) from the flow-through method to the deferral method for Sempra Energy. Under the flow-through method, we reduced our income tax expense by the amount of ITC in the year in which the qualifying assets were placed in service. Under the deferral method, we record ITC in the year when the qualifying assets are placed in service as a reduction to the cost of the asset that generated the ITC. This results in lower book depreciation over the life of the asset. This change has no historical or prospective impact on the California Utilities because ITC is effectively deferred as a result of the application of regulatory accounting required under GAAP.

The flow-through method and the deferral method are both acceptable under GAAP, but the deferral method is the preferred method. We believe that the deferral method is preferable for the ITC we receive because it recognizes ITC benefits over the same periods as the associated costs for which the ITC are intended to compensate.

We applied this change in accounting principle by retrospectively adjusting the historical financial statement amounts for all periods presented. Upon adopting the deferral method, we recorded an adjustment for the cumulative effect of the change in accounting principle to reduce Sempra Energy Consolidated retained earnings as of January 1, 2011 by $37 million.

Consolidation Variable Interest Entity Policy

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.

Goodwill And Intangible Assets Goodwill Policy

GOODWILL

Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized but is tested annually on October1 for impairment. Impairment of goodwill occurs when the carrying amount (book value) of goodwill exceeds its implied fair value. If the carrying value of the reporting unit, including goodwill, exceeds its fair value, and the book value of goodwill is greater than its fair value on the test date, we record a goodwill impairment loss.

Earnings Per Share Policy Text Block

EARNINGS PER SHARE

The following table provides the per share computations for our earnings for the three months and nine monthsended September 30, 2012 and 2011. 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.

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 recognizedand minus tax shortfalls recognizedare 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 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).

The dilution from unvested restricted stock awards (RSAs) and restricted stock units (RSUs) is also based on the treasury stock method.

Derivatives Policy Text Block

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) thatcould 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 (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 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 instruments 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.

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, which are typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings.

FOREIGN CURRENCY DERIVATIVES

We are exposed to exchange rate movements primarily as a result of our Mexican subsidiaries, which have U.S. dollar denominated 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 short-term 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.

Legal Costs Policy Text Block

LEGAL PROCEEDINGS

We accrue losses for legal proceedings 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 coverages and could materially adversely affect our business, cash flows, results of operations, and financial condition. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Millions, except Share data in Thousands, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011		Sep. 30, 2012	Sep. 30, 2011
REVENUES
Utilities	$ 2,170	$ 2,065	[1]	$ 6,099	$ 5,933	[1]
Energy-related businesses	337	511	[1]	880	1,499	[1]
Total revenues	2,507	2,576	[1]	6,979	7,432	[1]
Utilities [Abstract]
Cost of natural gas	(212)	(322)	[1]	(864)	(1,367)	[1]
Cost of electric fuel and purchased power	(515)	(408)	[1]	(1,252)	(976)	[1]
Energy-related businesses [Abstract]
Cost of natural gas, electric fuel and purchased power	(136)	(252)	[1]	(346)	(694)	[1]
Other cost of sales	(43)	(68)	[1]	(117)	(123)	[1]
Operation and maintenance	(732)	(691)	[1]	(2,123)	(2,003)	[1]
Depreciation and amortization	(280)	(251)	[1]	(803)	(729)	[1]
Franchise fees and other taxes	(89)	(84)	[1]	(264)	(259)	[1]
Equity (losses) earnings before income tax
Equity (losses) earnings before income tax, Rockies Express	(87)	10	[1]	(366)	29	[1]
Equity (losses) earnings before income tax, other	(7)	(22)	[1]	(9)	(33)	[1]
Remeasurement of equity method investments					277	[1]
Other income (expense), net	44	12	[1]	137	86	[1]
Interest income	5	6	[1]	14	21	[1]
Interest expense	(126)	(118)	[1]	(352)	(344)	[1]
Income before income taxes and equity earnings of certain unconsolidated subsidiaries	329	388	[1]	634	1,317	[1]
Income tax (expense) benefit	(49)	(75)	[1]	(48)	(289)	[1]
Equity earnings, net of income tax	10	6	[1]	29	45	[1]
Net income	290	319	[1]	615	1,073	[1]
Losses (earnings) attributable to noncontrolling interests	(20)	(29)	[1]	(44)	(21)	[1]
Preferred dividends of subsidiaries	(2)	(1)	[1]	(5)	(6)	[1]
Earnings	268	289	[1]	566	1,046	[1]
Basic earnings per common share:
Basic earnings per common share	$ 1.11	$ 1.21	[1]	$ 2.35	$ 4.36	[1]
Basic earnings per common share, weighted-average number of shares outstanding (thousands)	241,689	239,545	[1]	241,133	239,693	[1]
Diluted earnings per common share:
Diluted earnings per common share	$ 1.09	$ 1.20	[1]	$ 2.31	$ 4.32	[1]
Diluted earnings per common share, weighted-average number of shares outstanding (thousands)	245,802	241,880	[1]	245,013	241,955	[1]
Dividends declared per share of common stock	$ 0.60	$ 0.48	[1]	$ 1.80	$ 1.44	[1]
San Diego Gas and Electric Company and Subsidiary [Member]
Utility operating revenues
Electric	998	763		2,349	2,011
Natural gas	94	105		357	394
Total utility operating revenues	1,092	868		2,706	2,405
Utility operating expenses
Utility cost of natural gas	29	40		130	175
Utility cost of electric fuel and purchased power	301	207		604	534
Utility operation and maintenance	309	255		852	756
Utility depreciation and amortization	128	108		359	316
Utility franchise fees and other taxes	55	48		144	138
Total utility operating expenses	822	658		2,089	1,919
Utility operating income	270	210		617	486
Equity (losses) earnings before income tax
Other income (expense), net	5	26		59	55
Interest expense	(49)	(37)		(124)	(104)
Income before income taxes and equity earnings of certain unconsolidated subsidiaries	226	199		552	437
Income tax (expense) benefit	(38)	(63)		(151)	(154)
Net income	188	136		401	283
Losses (earnings) attributable to noncontrolling interests	(12)	(21)		(23)	(6)
Earnings	176	115		378	277
Preferred dividend requirements	(2)	(2)		(4)	(4)
Earnings attributable to common shares	174	113		374	273
Southern California Gas Company [Member]
Utility operating revenues
Total utility operating revenues	728	844		2,328	2,776
Utility operating expenses
Utility cost of natural gas	175	267		703	1,133
Utility operation and maintenance	316	331		933	946
Utility depreciation and amortization	91	83		268	246
Utility franchise fees and other taxes	27	28		91	94
Total utility operating expenses	609	709		1,995	2,419
Utility operating income	119	135		333	357
Equity (losses) earnings before income tax
Other income (expense), net	6	3		14	9
Interest income		1			1
Interest expense	(17)	(17)		(51)	(52)
Income before income taxes and equity earnings of certain unconsolidated subsidiaries	108	122		296	315
Income tax (expense) benefit	(37)	(41)		(105)	(106)
Net income	71	81		191	209
Earnings	71	81		191	209
Preferred dividend requirements	0	0		(1)	(1)
Earnings attributable to common shares	$ 71	$ 81		$ 190	$ 208

[1] As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

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DEBT AND CREDIT FACILITIES

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Debt and Credit Facilities

NOTE 6. DEBT AND CREDIT FACILITIES

Committed Lines of Credit

At September 30, 2012, Sempra Energy Consolidated had an aggregate of $4.1 billion in committed lines of credit to provide liquidity and to support commercial paper and variable-rate demand notes, the major components of which we detail below. Available unused credit on these lines at September 30, 2012 was $3.5 billion.

Sempra Energy

In March 2012,Sempra Energy entered into a new $1.067 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. serves as administrative agent for the syndicate of 24 lenders. No single lender has greater than a 7-percent share. The new facility replaced the $1.0 billion credit agreementthat was scheduled to expire in 2014.

Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and 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 $700 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, 2012, Sempra Energy had $47 million of letters of creditoutstanding supported by the facility.

Sempra Global

In March 2012,Sempra Global entered into a $2.189 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. serves as administrative agent for the syndicate of 25 lenders. No single lender has greater than a 7-percent share. The new facility replaced the $2.0 billion credit agreement that was scheduled to expire in 2014.

Sempra Energy guarantees Sempra Global's obligations under the credit facility. Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and Sempra Energy's credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter.

At September 30, 2012, Sempra Global had $545 million of commercial paper outstanding supported by the facility.At December 31, 2011, $400 million of commercial paper outstanding was classified as long-term debt based on management's intent and ability to maintain this level of borrowing on a long-term basis either supported by this credit facility or by issuing long-term debt. This classification has no impact on cash flows. As a result of issuances of long-term debt in the nine months ended September 30, 2012, as we discuss below, none of thecommercial paper outstanding at September 30, 2012is classified as long-term debt.

California Utilities

In March 2012,SDG&E and SoCalGas entered into a new combined $877 million, five-year syndicated revolving credit agreement expiring in March 2017. JPMorgan Chase Bank, N.A. serves as administrative agent for the syndicate of 24 lenders. No single lender has greater than a 7-percent share. The agreement permits each utility to individually borrow up to $658 million, subject to a combined limit of $877 million 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 $200 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. The new facility replaced the $800 million combined credit agreement that was scheduled to expire in 2014.

Borrowings under the facility bear interest at benchmark rates plus a margin that varies with market index rates and the borrowing utility's credit ratings. 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.

At September 30, 2012, SoCalGas had no outstanding borrowingsand SDG&E had $2 million of commercial paper outstanding supported by the facility. Available unused credit on the lineat September 30, 2012 was $656 million at SDG&E and $658 million at SoCalGas, subject to the combined limit on the facility of $877 million.

GUARANTEES

RBS Sempra Commodities

As we discuss in Note 4, in 2010 and early 2011, Sempra Energy, RBS and RBS Sempra Commodities sold substantially all of the businesses and assets within the partnership in four separate transactions. In connection with each of these transactions, the buyers were, subject to certain qualifications, obligated to replace any guarantees that we had issued in connection with the applicable businesses sold with guarantees of their own. The buyers have substantially completed this process with regard to all existing, open positions, except for one remaining position expected to terminate by January 2013. For those guarantees which have not been replaced, the buyers are obligated to indemnify us in accordance with the applicable transaction documents for any claims or losses in connection with the guarantees that we issued associated with the businesses sold.

At September 30, 2012, RBS Sempra Commodities no longer requires significant working capital support. However, we have provided back-up guarantees for a portion of RBS Sempra Commodities' remaining trading obligations. A few of these back-up guarantees may continue for a prolonged period of time. RBS has fully indemnified us for any claims or losses in connection with these arrangements, with the exception of those obligations for which JP Morgan has agreed to indemnify us. We discuss the indemnification release in Note 4. We discuss additional matters related to our investment in RBS Sempra Commodities in Note 10.

WEIGHTED AVERAGE INTEREST RATES

The weighted average interest rates on the total short-term debt outstanding at Sempra Energy were 0.82 percent and 0.93 percent at September 30, 2012 and December 31, 2011, respectively. The weighted average interest rate on the total short-term debt outstanding at SDG&E was 0.2percent at September 30, 2012.The weighted average interest rates at Sempra Energy at December 31, 2011 include interest rates for commercial paper borrowings classified as long-term, as we discuss above.

LONG-TERM DEBT

Sempra Energy

In March 2012, Sempra Energy publicly offered and sold $600 million of 2.30-percent notes maturing in 2017. In September 2012, Sempra Energy publicly offered and sold $500 million of 2.875-percent notes maturing in 2022.

SDG&E

In March 2012, SDG&E publicly offered and sold $250 million of 4.30-percent first mortgage bonds maturing in 2042.

In September 2012, SDG&E remarketed $161 million of variable rate demand notes at a fixed rate of 1.65 percent maturing in 2018 and $75 million of variable rate demand notes at a fixed rate of 4.00 percent maturing in 2039.

SoCalGas

In September 2012, SoCalGas publicly offered and sold $350 million of 3.75-percent first mortgage bonds maturing in 2042.

Sempra South American Utilities

In February 2012, Luz del Sur publicly offered and sold Peruvian corporate bonds, denominated in the localcurrency, in the amounts of $21 million at 5.97 percent maturing in 2017 and $9 million at 6.34 percent maturing in 2019. In July 2012, Luz del Sur publicly offered and sold $25 million of Peruvian corporate bonds, denominated in the local currency, at 5.44 percent and maturing in 2019.

Sempra Renewables

In June 2012, Sempra Renewables obtained a $117 million loan, the proceeds of which were applied to construction costs of the Copper Mountain Solar 1 project. The loan fully matures in December 2028. To partially moderate its exposure to interest rate changes, Sempra Renewables has also entered into floating-to-fixed interest rate swapsmaturing December 2028. Accordingly, $88 million of this loan has interest rates that are effectively fixed at 4.54 percent. The remaining balance bears interest at rates varying with market rates (2.86 percent at September 30, 2012).

INTERESTRATE SWAPS

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

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OTHER FINANCIAL DATA

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Other Financial Data

NOTE 5. OTHER FINANCIAL DATA

U. S. Treasury Grants Receivable

As of September 30, 2012, Sempra Renewables has recorded grants receivable totaling $181 million. Based on eligible costs at its Mesquite Solar 1 and Copper Mountain Solar 2 generating facilities, the grants are recognized as receivables when the projects, or portions of projects, are placed into service. The grants are expected to be received in 2013.

Inventories

The components of inventories by segment are as follows:

INVENTORY BALANCES
(Dollars in millions)
	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	Natural Gas				Materials and supplies				Total
SDG&E	$	2	$	6	$	81	$	76	$	83	$	82
SoCalGas		142		128		24		23		166		151
Sempra South American Utilities		―		―		37		36		37		36
Sempra Mexico		10		10		8		7		18		17
Sempra Natural Gas		85		51		9		9		94		60
Sempra Energy Consolidated	$	239	$	195	$	159	$	151	$	398	$	346

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 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 impacts on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility's useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. SDG&E determines if it is the primary beneficiary in these cases based on 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-megawatt (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 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. SDG&E and Sempra Energy have consolidated Otay Mesa VIE since the second quarter of 2007. Otay Mesa VIE's equity of $90 million at September 30, 2012 and $102 million at December 31, 2011 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 $347 million at September 30, 2012, 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.

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 as of September 30, 2012. 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. In all other cases, we have determined that these contracts are not variable interests in a VIE and therefore are not subject to the requirements of GAAP concerning the consolidation of VIEs.

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 financial statements of other consolidated VIEs are not material to the financial statements of Sempra Energy. The captions on 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,
	2012		2011		2012		2011
Operating revenues
Electric	$	―	$	―	$	―	$	―
Natural gas		―		―		―		―
Total operating revenues		―		―		―		―
Operating expenses
Cost of electric fuel and purchased power		(26)		(29)		(66)		(55)
Operation and maintenance		4		1		15		23
Depreciation and amortization		7		7		19		20
Total operating expenses		(15)		(21)		(32)		(12)
Operating income		15		21		32		12
Other income (expense), net		―		4		(1)		―
Interest expense		(3)		(4)		(8)		(6)
Income before income taxes/Net income		12		21		23		6
Earnings attributable to noncontrolling interest		(12)		(21)		(23)		(6)
Earnings	$	―	$	―	$	―	$	―

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

GOODWILL

Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized but is tested annually on October1 for impairment. Impairment of goodwill occurs when the carrying amount (book value) of goodwill exceeds its implied fair value. If the carrying value of the reporting unit, including goodwill, exceeds its fair value, and the book value of goodwill is greater than its fair value on the test date, we record a goodwill impairment loss.

Goodwill included on the Sempra Energy Condensed Consolidated Balance Sheets is recorded as follows:

GOODWILL
(Dollars in millions)
			Sempra
			South American		Sempra		Sempra
			Utilities		Mexico		Natural Gas		Total
Balance as of December 31, 2011		$	949	$	25	$	62	$	1,036
Foreign currency translation(1)			63		―		―		63
Acquisition of subsidiary			―		―		10		10
Balance at September 30, 2012		$	1,012	$	25	$	72	$	1,109
(1)	We record the offset of this fluctuation to other comprehensive income.

We provide additional information concerning goodwill in Note 3 above and Notes 1 and 3of the Notes to Consolidated Financial Statements in the Updated Annual Report. 

PENSION AND OTHER POSTRETIREMENT BENEFITS

Remeasurement

TheSoCalGas union collective bargaining agreement (CBA) covering wages, hours, working conditions and medical and other benefit plans was ratified on March 1, 2012 and is effective January 1, 2012 through September 30, 2015. The new CBA includes a change in plans offered for post-65 medical benefits. As a result, SoCalGas changed the option for administering the Medicare Part D benefit to an Employer Group Waiver Plan (EGWP). The EGWP allows a plan sponsor to contract with a Medicare Part D sponsor to receive the benefit of the subsidy through reduced premiums.Because this change in benefits is a significant event under GAAP, SoCalGas was required to remeasure the benefit obligations for this postretirement welfare plan as of February 29, 2012 and determined that a discount rate of 4.65% was appropriate. The effect of the remeasurement was a $66 million decrease in the recorded liability for other postretirement benefits as of March 31, 2012 at SoCalGas and Sempra Energy Consolidated. We discuss the Medicare Part D benefit in Note 8 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Employee Stock Ownership Plan (ESOP)

Sempra Energy terminated the ESOP effective June 30, 2012, as all ESOP debt was paid and all shares were released from the ESOP Trust as of that date. We describe the ESOP and ESOP debt in Note 8 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

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,				Three months ended September 30,
	2012		2011		2012		2011
Service cost	$	23	$	20	$	4	$	8
Interest cost		40		41		11		16
Expected return on assets		(38)		(36)		(13)		(12)
Amortization of:
Prior service cost		―		1		―		―
Actuarial loss		12		8		2		4
Settlement		1		1		―		―
Regulatory adjustment		9		31		3		2
Total net periodic benefit cost	$	47	$	66	$	7	$	18
	Nine months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Service cost	$	68	$	63	$	19	$	23
Interest cost		122		126		39		49
Expected return on assets		(116)		(109)		(40)		(36)
Amortization of:
Prior service cost (credit)		2		3		(2)		―
Actuarial loss		35		26		9		13
Settlement		8		11		―		―
Regulatory adjustment		(9)		6		8		6
Total net periodic benefit cost	$	110	$	126	$	33	$	55

NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended September 30,				Three months ended September 30,
	2012		2011		2012		2011
Service cost	$	7	$	6	$	1	$	1
Interest cost		11		12		2		2
Expected return on assets		(11)		(10)		(1)		(1)
Amortization of:
Prior service cost		―		―		1		1
Actuarial loss		4		2		―		―
Settlement		(1)		―		―		―
Regulatory adjustment		7		15		1		1
Total net periodic benefit cost	$	17	$	25	$	4	$	4
	Nine months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Service cost	$	21	$	21	$	5	$	5
Interest cost		34		37		6		7
Expected return on assets		(35)		(35)		(5)		(5)
Amortization of:
Prior service cost		1		1		3		3
Actuarial loss		11		7		―		―
Settlement		1		1		―		―
Regulatory adjustment		7		13		2		2
Total net periodic benefit cost	$	40	$	45	$	11	$	12

NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended September 30,				Three months ended September 30,
	2012		2011		2012		2011
Service cost	$	13	$	10	$	2	$	7
Interest cost		24		24		9		12
Expected return on assets		(23)		(21)		(10)		(10)
Amortization of:
Prior service cost (credit)		―		1		(1)		(1)
Actuarial loss		6		4		1		4
Regulatory adjustment		2		16		2		1
Total net periodic benefit cost	$	22	$	34	$	3	$	13
	Nine months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Service cost	$	40	$	34	$	12	$	17
Interest cost		74		74		31		39
Expected return on assets		(72)		(64)		(33)		(30)
Amortization of:
Prior service cost (credit)		1		2		(5)		(3)
Actuarial loss		17		12		8		13
Settlement		1		1		―		―
Regulatory adjustment		(16)		(7)		6		4
Total net periodic benefit cost	$	45	$	52	$	19	$	40

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 2012:

	Sempra Energy
(Dollars in millions)	Consolidated		SDG&E		SoCalGas
Contributions through September 30, 2012:
Pension plans	$	111	$	36	$	45
Other postretirement benefit plans		32		10		19
Total expected contributions in 2012:
Pension plans	$	123	$	45	$	47
Other postretirement benefit plans		41		13		23

Expected contributions to our pension plans in 2012 have decreased significantly due to the passage of legislation in July 2012, the Moving Ahead for Progress in the 21st Century Act, that significantly reduces the minimum contributions required for single employer defined benefit plans,but increases premiums to the Pension Benefit Guaranty Corporation.

EARNINGS PER SHARE

The following table provides the per share computations for our earnings for the three months and nine monthsended September 30, 2012 and 2011. 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,
		2012		2011(1)		2012		2011(1)
Numerator:
Earnings/Income attributable to common shareholders		$	268	$	289	$	566	$	1,046
Denominator:
Weighted-average common shares
outstanding for basic EPS			241,689		239,545		241,133		239,693
Dilutive effect of stock options, restricted
stock awards and restricted stock units			4,113		2,335		3,880		2,262
Weighted-average common shares
outstanding for diluted EPS			245,802		241,880		245,013		241,955
Earnings per share:
Basic		$	1.11	$	1.21	$	2.35	$	4.36
Diluted		$	1.09	$	1.20	$	2.31	$	4.32
(1)	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

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 recognizedand minus tax shortfalls recognizedare 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 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 nosuch antidilutivestock options outstanding during the three months ended September 30, 2012 and 40,000 such antidilutive stock options outstanding during the nine months ended September 30, 2012. We had 2,112,880 and 2,111,839 such stock options outstanding during the three months and ninemonths ended September 30, 2011, respectively.

We had no stock options outstanding duringeither the three monthsornine months ended September 30, 2012that were antidilutive because of the unearned compensation and windfall tax benefits included in the assumed proceeds under the treasury stock method. We had no such stock options during the three months ended September 30, 2011 and 900 such antidilutive stock options during the nine months ended September 30, 2011.

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 and 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 recognized 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 3,387antidilutive RSUs from the application of unearned compensation in the treasury stock method for the three months and 1,881 such antidilutive RSUs for the ninemonths ended September 30, 2012.There were1,109such antidilutiveRSUs forthe three months ended September 30, 2011 and no such antidilutive RSUs for the ninemonths ended September 30, 2011. There were nosuch antidilutive RSAs for the threemonths ended September 30, 2012 and 14,319 such antidilutive RSAs for the ninemonths ended September 30, 2012.There wereno such antidilutive RSAs for the three months and ninemonths ended September 30, 2011.

Each performance-based RSU represents the right to receive between zero and 1.5 shares of Sempra Energy common stock based on Sempra Energy's four-year cumulative total shareholder return compared to the Standard &Poor's(S&P) 500 Utilities Index, as follows:

Four-Year Cumulative Total Shareholder Return Ranking versus S&P 500 Utilities Index(1)	Number of Sempra Energy Common Shares Received for Each Restricted Stock Unit(2)
75th Percentile or Above	1.5
50th Percentile	1
35th Percentile or Below	―
(1) If Sempra Energy ranks at or above the 50th percentile compared to the S&P 500 Index, participants will receive a minimum of 1.0 share for each restricted stock unit.
(2) Participants may also receive additional shares for dividend equivalents on units subject to restricted stock units, which are reinvested to purchase additional units that become subject to the same vesting conditions as the restricted stock units to which the dividends relate.

RSAs have a maximum potential of 100 percent vesting. We include our performance-based RSUs in potential dilutive shares at zero to 150 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 index, dilutive RSU shares may vary widely from period-to-period. We include our RSAs, which are solely service-based, in potential dilutive shares at 100 percent.

RSUs and RSAs may be excluded from potential dilutive shares by the application of unearned compensation in the treasury stock method, as we discuss above, or because performance goals are currently not met. The maximum excluded RSAs and RSUs, assuming performance goals were met at maximum levels, were 2,349,338 and 2,523,343 for the three monthsand ninemonths ended September 30, 2012, respectively, and 3,473,578 and 3,630,253 for the three months and nine months ended September 30,2011, respectively

COMMON STOCK REPURCHASE PROGRAM

In September 2010, we entered into a share repurchase program under which we prepaid $500 million to repurchase shares of our common stock in a share forward transaction. The program was completed in March 2011 with a total of 9,574,435 shares repurchased at an average price of $52.22 per share. Our outstanding shares used to calculate earnings per share were reduced by the number of shares repurchased when they were delivered to us, and the $500 million purchase price was recorded as a reduction in shareholders' equity upon its prepayment. We received 5,670,006 shares during the quarter ended September 30, 2010; 2,407,994 shares on October 4, 2010 and 1,496,435 shares on March 22, 2011.We discuss the repurchase program further in Note 13 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

PREFERRED STOCK OF SUBSIDIARY

On June 30, 2011, PE redeemed all five series of its outstanding preferred stock for $81 million. Each series was redeemed for cash at redemption prices ranging from $100 to $101.50 per share, plus accrued dividends up to the redemption date of an aggregate of $1 million. The redeemed shares are no longer outstanding and represent only the right to receive the applicable redemption price, to the extent the shares have not yet been presented for payment. We provide more detail concerning PE's preferred stock in Note 12 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

SHARE-BASED COMPENSATION

We discuss our share-based compensation plans in Note 9 of the Notes to Consolidated Financial Statements in theUpdated Annual Report. We recorded share-based compensation expense, net of income taxes, of $5 million and $7 million for the three months ended September 30, 2012 and 2011, respectively,and $18 million and $20 million for the nine months ended September 30, 2012 and 2011, respectively. Pursuant to our share-based compensation plans, we granted 927,734RSUs and 18,487RSAs during the nine months ended September30, 2012, primarily inJanuary.

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. The following table shows capitalized financing costs for the three months and nine monthsended September 30, 2012 and 2011.

CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Sempra Energy Consolidated:
AFUDC related to debt	$	5	$	10	$	32	$	27
AFUDC related to equity		13		26		80		67
Other capitalized financing costs		13		6		40		20
Total Sempra Energy Consolidated	$	31	$	42	$	152	$	114
SDG&E:
AFUDC related to debt	$	3	$	8	$	26	$	22
AFUDC related to equity		6		21		61		54
Total SDG&E	$	9	$	29	$	87	$	76
SoCalGas:
AFUDC related to debt	$	2	$	2	$	6	$	5
AFUDC related to equity		7		5		19		13
Total SoCalGas	$	9	$	7	$	25	$	18

COMPREHENSIVE INCOME

The amounts for comprehensive income in the Condensed Consolidated Statements of Comprehensive Income are net of income tax expense (benefit) as follows:

INCOME TAX EXPENSE (BENEFIT) ASSOCIATED WITH OTHER COMPREHENSIVE INCOME
(Dollars in millions)
		Three months ended September 30,
		2012						2011
		Share-		Non-				Share-		Non-
		holders'		controlling		Total		holders'		controlling		Total
		Equity(1)		Interests		Equity		Equity(1)		Interests		Equity
Sempra Energy Consolidated:
Foreign currency translation adjustments		$	―	$	―	$	―	$	(1)	$	―	$	(1)
Net actuarial (loss) gain			(7)		―		(7)		1		―		1
Financial instruments			(1)		―		(1)		(11)		―		(11)
SoCalGas:
Financial instruments		$	1	$	―	$	1	$	―	$	―	$	―
		Nine months ended September 30,
		2012						2011
		Share-		Non-				Share-		Non-
		holders'		controlling		Total		holders'		controlling		Total
		Equity(1)		Interests		Equity		Equity(1)		Interests		Equity
Sempra Energy Consolidated:
Foreign currency translation adjustments		$	―	$	―	$	―	$	(1)	$	―	$	(1)
Net actuarial (loss) gain			(4)		―		(4)		5		―		5
Financial instruments			(5)		―		(5)		(11)		―		(11)
SoCalGas:
Financial instruments		$	1	$	―	$	1	$	1	$	―	$	1
(1)	Shareholders’ equity of Sempra Energy Consolidated or SoCalGas as indicated in left margin.

Income tax amounts associated with other comprehensive income during the three months and nine monthsended September30,2012and 2011at SDG&E were negligible.

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS

The following two tables provide a reconciliation of Sempra Energy's and SDG&E's shareholders' equity and noncontrolling interests for thenine months ended September 30, 2012 and 2011.

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS
(Dollars in millions)
		Sempra
		Energy		Non-
		Shareholders’		controlling		Total
		Equity		Interests		Equity
Balance at December 31, 2011	$	9,775	$	403	$	10,178
Comprehensive income		671		42		713
Preferred dividends of subsidiaries		(5)		―		(5)
Share-based compensation expense		33		―		33
Common stock dividends declared		(435)		―		(435)
Issuance of common stock		50		―		50
Repurchase of common stock		(16)		―		(16)
Common stock released from ESOP		9		―		9
Equity contributed by noncontrolling interest		―		5		5
Distributions to noncontrolling interests		―		(36)		(36)
Balance at September 30, 2012	$	10,082	$	414	$	10,496
Balance at December 31, 2010	$	8,990	$	211	$	9,201
Comprehensive income (loss)		879		(14)		865
Preferred dividends of subsidiaries		(6)		―		(6)
Share-based compensation expense		36		―		36
Common stock dividends declared		(346)		―		(346)
Issuance of common stock		22		―		22
Tax benefit related to share-based compensation		6		―		6
Repurchase of common stock		(18)		―		(18)
Common stock released from ESOP		15		―		15
Distributions to noncontrolling interests		―		(9)		(9)
Equity contributed by noncontrolling interest		―		6		6
Acquisition of South American entities		―		279		279
Purchase of noncontrolling interests in subsidiary		(4)		(39)		(43)
Redemption of preferred stock of subsidiary		―		(80)		(80)
Balance at September 30, 2011	$	9,574	$	354	$	9,928

SHAREHOLDER’S EQUITY AND NONCONTROLLING INTEREST
(Dollars in millions)
		SDG&E		Non-
		Shareholder’s		controlling		Total
		Equity		Interest		Equity
Balance at December 31, 2011	$	3,739	$	102	$	3,841
Comprehensive income		378		10		388
Preferred stock dividends declared		(4)		―		(4)
Distributions to noncontrolling interest		―		(22)		(22)
Balance at September 30, 2012	$	4,113	$	90	$	4,203
Balance at December 31, 2010	$	3,108	$	113	$	3,221
Comprehensive income (loss)		278		(28)		250
Preferred stock dividends declared		(4)		―		(4)
Capital contribution		200		―		200
Equity contributed by noncontrolling interest		―		6		6
Balance at September 30, 2011	$	3,582	$	91	$	3,673

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. Net income or loss attributable to the noncontrolling interests is separately identified on the Condensed Consolidated Statements of Operations, and comprehensive income attributable to the noncontrolling interests is separately identified on the Condensed Consolidated Statements of Comprehensive Income.

The preferred stock of SoCalGas is presented at Sempra Energy as a noncontrolling interest at September 30, 2012 and December 31, 2011. The preferred stock of SDG&E is contingently redeemable preferred stock. At Sempra Energy, the preferred stock dividends of both SDG&E and SoCalGas are charges against income related to noncontrolling interests. We provide additional information concerning preferred stock in Note 12 of the Notes to Consolidated Financial Statements in the Updated Annual Report. 

At September 30, 2012 and December 31, 2011, Sempra Energy Consolidated reported the following other noncontrolling ownership interests held by others 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, 2012		December 31, 2011
Bay Gas Storage, Ltd.(1)		9	%	$	19	$	17
Southern Gas Transmission Company(1)		49			1		1
Liberty Gas Storage, LLC(1)		25			13		9
Tecsur		10			4		4
Luz del Sur		20			230		216
Chilquinta Energía subsidiaries		15 - 43			37		34
Otay Mesa VIE (at SDG&E)		100			90		102
Total Sempra Energy				$	394	$	383
(1)	Part of Sempra Natural Gas.

TRANSACTIONS WITH AFFILIATES

Loans to Unconsolidated Affiliates

Sempra South American Utilities hasa U.S. dollar-denominated loan to Camuzzi Gas del Sur S.A., an affiliate of the segment's Argentine investments, which we discuss in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report. At September 30, 2012,the loanhas an$18 million principalbalance outstanding plus $7 million of accumulated interestat a variable interest rate (7.41percent as ofSeptember 30, 2012). In June 2012, the maturity date of the loan wasextended from June 30, 2012to June 30, 2013.The loan was fully reserved atSeptember 30, 2012 and December 31, 2011.

Investments

Sempra Energy, at Parent and Other, has an investment in bonds issued by Chilquinta Energía that we discuss in Note 5 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Other Affiliate Transactions

Sempra Energy, SDG&E and SoCalGas provide certain services to each otherand are charged an allocable share of the cost of such services. Amounts due to/from affiliates are as follows:

AMOUNTS DUE TO AND FROM AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
		September 30,		December 31,
		2012		2011
SDG&E
Current:
Due from SoCalGas		$	16	$	2
Due from various affiliates			1		65
		$	17	$	67
Due to Sempra Energy		$	20	$	14
Income taxes due from Sempra Energy(1)		$	149	$	97
SoCalGas
Current:
Due from Sempra Energy		$	280	$	23
Due from various affiliates			―		17
		$	280	$	40
Due to SDG&E		$	16	$	2
Income taxes due from Sempra Energy(1)		$	15	$	17
(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 the companies’ having always filed a separate return.

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

REVENUES FROM UNCONSOLIDATED AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
SDG&E	$	2	$	3	$	6	$	6
SoCalGas		17		13		48		38

Transactions with RBS Sempra Commodities

Several of our segmentshave engaged in transactions with RBS Sempra Commodities. As a result of the divestiture of substantially all of RBS Sempra Commodities' businesses, transactions between our segments and RBS Sempra Commodities were assigned over time to the buyers of the joint venture businesses.The assignments of the related contracts were substantially completed by May 1, 2011. Amounts in our Condensed Consolidated Statements of Operations related to these transactions are as follows:

AMOUNTS RECORDED FOR TRANSACTIONS WITH RBS SEMPRA COMMODITIES
(Dollars in millions)
		Three months ended September 30, 2011(1)		Nine months ended September 30, 2011(1)
Revenues:
Sempra Mexico		$	―	$	37
Sempra Natural Gas			―		7
Cost of natural gas:
Sempra Mexico		$	3	$	74
Sempra Natural Gas			―		3
(1)	With the exception of Sempra Mexico, whose contract with RBS Sempra Commodities expired in July 2011, amounts only include activities prior to May 1, 2011, the date by which substantially all the contracts with RBS Sempra Commodities were assigned to buyers of the joint venture businesses.

OTHER INCOME, NET

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

OTHER INCOME, NET
(Dollars in millions)
		Three months ended September 30,				Nine months ended September 30,
		2012		2011		2012		2011
Sempra Energy Consolidated:
Allowance for equity funds used during construction		$	13	$	26	$	80	$	67
Investment gains (losses)(1)			17		(6)		27		13
Gains (losses) on interest rate and foreign exchange instruments, net			1		(26)		11		(14)
Regulatory interest, net(2)			―		―		1		1
Sundry, net			13		18		18		19
Total		$	44	$	12	$	137	$	86
SDG&E:
Allowance for equity funds used during construction		$	6	$	21	$	61	$	54
Regulatory interest, net(2)			―		―		1		1
Sundry, net			(1)		5		(3)		―
Total		$	5	$	26	$	59	$	55
SoCalGas:
Allowance for equity funds used during construction		$	7	$	5	$	19	$	13
Sundry, net			(1)		(2)		(5)		(4)
Total		$	6	$	3	$	14	$	9
(1)	Represents investment gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
(2)	Interest on regulatory balancing accounts.

INCOME TAXES

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
		Three months ended September 30,
	2012					2011
			Effective				Effective
		Income Tax	Income			Income Tax	Income
		Expense	Tax Rate			Expense	Tax Rate
Sempra Energy Consolidated	$	49	15	%	$	75	19	%
SDG&E		38	17			63	32
SoCalGas		37	34			41	34
		Nine months ended September 30,
	2012					2011
			Effective				Effective
		Income Tax	Income			Income Tax	Income
		Expense	Tax Rate			Expense	Tax Rate
Sempra Energy Consolidated	$	48	8	%	$	289	22	%
SDG&E		151	27			154	35
SoCalGas		105	35			106	34

Changes in Effective Income Tax Rates

Sempra Energy Consolidated

The lower effective income tax rate in the three months ended September 30, 2012 was primarily due to:

• $38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012. The change in income tax treatment was made pursuant to an Internal Revenue Service Revenue Procedure allowing certain capitalized repair costs for electric transmission and distribution assets to be deducted from taxable income when incurred for tax years beginning on or after January 1, 2011; and
• higher planned renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; offset by
• higher income tax expense in 2012 due to Mexican currency translation and inflation adjustments; and

• higher income tax expense due to unfavorable resolution of prior years' income tax items.

  The lower effective income tax rate in the nine months ended September 30, 2012 was primarily due to:

• $54 million income tax benefit primarily associated with our decision to hold life insurance contracts kept in support of certain benefit plans to term. Previously, we took the position that we might cash in or sell these contracts before maturity, which required that we record deferred income taxes on unrealized gains on investments held within the insurance contracts;
• $38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012, as discussed above; and
• higher planned renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; offset by
• lower income in 2012 in countries with lower statutory income tax rates; such income was higher in 2011 due to the $277 million non-taxable gain from our equity method investments related to our acquisition from AEI of its investments in Chile and Peru;
• higher income tax expense in 2012 due to Mexican currency translation and inflation adjustments;
• higher income tax expense due to unfavorable resolution of prior years' income tax items;and

• higher U.S. income tax on non-U.S. non-operating activity due to the expiration of the look-through rule, as we discuss below.

  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 spread evenly over the year. The forecasted items, anticipated on a full year basis, may include, among others, self-developed software, repairs to certain utility plant fixed 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, and depreciation on a certain portion of utility plant assets. Items that cannot be reliably forecasted (e.g., adjustments related to prior years' income tax items, Mexican currency translation and inflation adjustments, deferred income tax benefit associated with the impairment of a book investment, etc.) are recorded in the interim period in which they actually occur, which can result in variability to income tax expense.

  We have used grant accounting for certain assets placed into service in 2012, including assets that were under construction in 2011, in anticipation of applying for cash grants. Grant accounting for cash grants is very similar to the deferral method of accounting for investment tax credits, the primary difference being the recording of a grant receivable instead of an income tax receivable.

  Under the deferral method of accounting for ITC and under grant accounting for cash grants, a deferred income tax benefit, on day one, is reflected in income tax expense by recording a deferred tax asset when renewable energy assets are placed in service. This deferred tax asset results from the day-one difference in the income tax basis and financial statement basis of the renewable energy assets, referred to as the “day-one basis difference.” The financial statement basis of the assets is reduced by 100 percent of the ITC or grant expected; U.S. federal income tax basis is reduced by only 50 percent for both ITC and grants; and state income tax basis is reduced 50 percent for grants and not at all for ITC.

  In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Act) was signed into law. The 2010 Tax Act extended for years 2010 and 2011 the U.S. federal income tax law known as the look-through rule. This rule allows, under certain situations, for certain non-operating activity (e.g., dividend income, royalty income, interest income, rental income, etc.), of a greater than 50-percent owned non-U.S. subsidiary, to not be taxed under U.S. federal income tax law. As of September 30, 2012, this rule has not yet been extended beyond 2011, which has a negative impact on Sempra Energy's effective income tax rate for 2012.

  SDG&E

  The decrease in theeffective income tax rate in the three months ended September 30, 2012 was primarily due to:

• $38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012.  The change in income tax treatment was made pursuant to an Internal Revenue Service Revenue Procedure allowing certain capitalized repair costs for electric transmission and distribution assets to be deducted from taxable income when incurred for tax years beginning on or after January 1, 2011; and
• higher favorable resolutions of prior years' income tax items; offset by
• the impact of Otay Mesa VIE, as we discuss below; and

• lower exclusions from taxable income of the equity portion of AFUDC.

  The decrease in the effective tax rate in the nine months ended September 30, 2012 was primarily due to:

• $38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012, as discussed above;
• the impact of Otay Mesa VIE, as we discuss below;
• lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and
• higher favorable resolutions of prior years' income tax items; offset by

• lower exclusions from taxable income of the equity portion of AFUDC.

  Results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is consolidated, and therefore, their effective income tax rates are impacted by the VIE's stand-alone effective income tax rate.

  SoCalGas

  While the effective income tax rate for the three months ended September 30, 2012 did not change significantly from the same period in 2011, it wasimpacted by:

• lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and

• higher exclusions from taxable income of the equity portion of AFUDC; offset by

• lower deductions for cost of removal of utility plant fixed assets.

The increase in the effective income tax rate in the nine months ended September 30, 2012 was primarily due to:

• lower deductions for self-developed software costs; offset by

• lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and

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

The California Public Utilities Commission (CPUC) requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income taxes are not recorded to deferred income tax expense, but rather to a regulatory asset or liability. 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 to a certain portion of utility plant fixed assets
• the equity portion of AFUDC
• cost of removal of utility plant assets
• self-developed software costs

• depreciation on a certain portion of utility plant fixed assets

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FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Sep. 30, 2012

Fair Value Measurements (Tables) [Abstract]

Fair Value of Financial Instruments Table

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
		September 30, 2012
		Carrying		Fair Value
		Amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Investments in affordable housing partnerships(1)		$	16	$	―	$	―	$	46	$	46
Total long-term debt(2)			11,727		―		12,556		755		13,311
Preferred stock of subsidiaries			99		―		108		―		108
SDG&E:
Total long-term debt(3)		$	4,137	$	―	$	4,308	$	347	$	4,655
Contingently redeemable preferred stock			79		―		86		―		86
SoCalGas:
Total long-term debt(4)		$	1,662	$	―	$	1,872	$	―	$	1,872
Preferred stock			22		―		24		―		24
		December 31, 2011
		Carrying		Fair Value
		Amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Investments in affordable housing partnerships(1)		$	21	$	―	$	―	$	48	$	48
Total long-term debt(2)			9,826		―		10,447		600		11,047
Preferred stock of subsidiaries			99		―		106		―		106
SDG&E:
Total long-term debt(3)		$	3,895	$	―	$	3,933	$	355	$	4,288
Contingently redeemable preferred stock			79		―		86		―		86
SoCalGas:
Total long-term debt(4)		$	1,313	$	―	$	1,506	$	―	$	1,506
Preferred stock			22		―		23		―		23
(1)	We discuss our investments in affordable housing partnerships in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
(2)	Before reductions for unamortized discount (net of premium) of $17 million at September 30, 2012 and $16 million at December 31, 2011, and excluding capital leases of $192 million at September 30, 2012 and $204 million at December 31, 2011, and commercial paper classified as long-term debt of $400 million at December 31, 2011. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
(3)	Before reductions for unamortized discount of $12 million at September 30, 2012 and $11 million at December 31, 2011, and excluding capital leases of $187 million at September 30, 2012 and $193 million at December 31, 2011.
(4)	Before reductions for unamortized discount of $4 million at September 30, 2012 and $3 million at December 31, 2011, and excluding capital leases of $5 million at September 30, 2012 and $11 million at December 31, 2011.

Nuclear Decommissioning Trusts Table

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
			Cost		Gains		Losses		Value
As of September 30, 2012:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies(1)		$	134	$	12	$	―	$	146
Municipal bonds(2)			60		6		―		66
Other securities(3)			114		9		―		123
Total debt securities			308		27		―		335
Equity securities			249		284		(4)		529
Cash and cash equivalents			28		―		―		28
Total		$	585	$	311	$	(4)	$	892
As of December 31, 2011:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		$	157	$	13	$	―	$	170
Municipal bonds			72		5		―		77
Other securities			76		3		(1)		78
Total debt securities			305		21		(1)		325
Equity securities			246		227		(5)		468
Cash and cash equivalents			11		―		―		11
Total		$	562	$	248	$	(6)	$	804
(1)	Maturity dates are 2013-2042
(2)	Maturity dates are 2012-2057
(3)	Maturity dates are 2013-2111

Sales of Securities Table

SALES OF SECURITIES
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Proceeds from sales	$	204	$	294	$	524	$	384
Gross realized gains		3		27		12		29
Gross realized losses		(1)		(8)		(6)		(10)

Fair Value of Cash Collateral Receivables Not Offset on the Condensed Consolidated Balance Sheets Table

	September 30,		December 31,
(Dollars in millions)	2012		2011
Sempra Energy Consolidated	$	46	$	20
SDG&E		20		10
SoCalGas		4		2

Recurring Fair Value Measures Table

RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		At fair value as of September 30, 2012
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	529	$	―	$	―	$	―	$	529
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			72		74		―		―		146
Municipal bonds			―		66		―		―		66
Other securities			―		123		―		―		123
Total debt securities			72		263		―		―		335
Total nuclear decommissioning trusts(1)			601		263		―		―		864
Interest rate instruments			―		73		―		―		73
Commodity contracts subject to rate recovery			21		―		23		―		44
Commodity contracts not subject to rate recovery			19		19		―		―		38
Investments			1		―		―		―		1
Total		$	642	$	355	$	23	$	―	$	1,020
Liabilities:
Interest rate and foreign exchange instruments		$	―	$	136	$	―	$	―	$	136
Commodity contracts subject to rate recovery			32		8		―		(32)		8
Commodity contracts not subject to rate recovery			9		30		―		(13)		26
Total		$	41	$	174	$	―	$	(45)	$	170
		At fair value as of December 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	468	$	―	$	―	$	―	$	468
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			92		78		―		―		170
Municipal bonds			―		77		―		―		77
Other securities			―		78		―		―		78
Total debt securities			92		233		―		―		325
Total nuclear decommissioning trusts(1)			560		233		―		―		793
Interest rate instruments			―		66		―		―		66
Commodity contracts subject to rate recovery			10		1		23		―		34
Commodity contracts not subject to rate recovery			15		35		―		(2)		48
Investments			5		―		―		―		5
Total		$	590	$	335	$	23	$	(2)	$	946
Liabilities:
Interest rate instruments		$	1	$	124	$	―	$	―	$	125
Commodity contracts subject to rate recovery			61		13		―		(61)		13
Commodity contracts not subject to rate recovery			1		52		―		(4)		49
Total		$	63	$	189	$	―	$	(65)	$	187
(1)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
		At fair value as of September 30, 2012
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	529	$	―	$	―	$	―	$	529
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			72		74		―		―		146
Municipal bonds			―		66		―		―		66
Other securities			―		123		―		―		123
Total debt securities			72		263		―		―		335
Total nuclear decommissioning trusts(1)			601		263		―		―		864
Commodity contracts subject to rate recovery			19		―		23		―		42
Commodity contracts not subject to rate recovery			2		―		―		―		2
Total		$	622	$	263	$	23	$	―	$	908
Liabilities:
Interest rate instruments		$	―	$	85	$	―	$	―	$	85
Commodity contracts subject to rate recovery			32		7		―		(32)		7
Total		$	32	$	92	$	―	$	(32)	$	92
		At fair value as of December 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	468	$	―	$	―	$	―	$	468
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			92		78		―		―		170
Municipal bonds			―		77		―		―		77
Other securities			―		78		―		―		78
Total debt securities			92		233		―		―		325
Total nuclear decommissioning trusts(1)			560		233		―		―		793
Commodity contracts subject to rate recovery			9		―		23		―		32
Commodity contracts not subject to rate recovery			1		―		―		―		1
Total		$	570	$	233	$	23	$	―	$	826
Liabilities:
Interest rate instruments		$	―	$	81	$	―	$	―	$	81
Commodity contracts subject to rate recovery			61		12		―		(61)		12
Total		$	61	$	93	$	―	$	(61)	$	93
(1)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
	At fair value as of September 30, 2012
								Collateral
		Level 1		Level 2		Level 3		netted		Total
Assets:
Commodity contracts subject to rate recovery	$	2	$	―	$	―	$	―	$	2
Commodity contracts not subject to rate recovery		2		―		―		―		2
Total	$	4	$	―	$	―	$	―	$	4
Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
Total	$	―	$	1	$	―	$	―	$	1
	At fair value as of December 31, 2011
								Collateral
		Level 1		Level 2		Level 3		netted		Total
Assets:
Commodity contracts subject to rate recovery	$	1	$	1	$	―	$	―	$	2
Commodity contracts not subject to rate recovery		2		―		―		―		2
Total	$	3	$	1	$	―	$	―	$	4
Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
Total	$	―	$	1	$	―	$	―	$	1

Recurring Fair Value Measures Level 3 Rollforward Table

	Three months ended September 30,
(Dollars in millions)	2012		2011
Balance as of July 1	$	13	$	3
Realized and unrealized gains		16		5
Allocated transmission instruments		17		―
Settlements		(23)		(5)
Balance as of September 30	$	23	$	3
Change in unrealized gains or losses relating to
instruments still held at September 30	$	―	$	―

	Nine months ended September 30,
(Dollars in millions)	2012		2011
Balance as of January 1	$	23	$	2
Realized and unrealized gains		23		17
Allocated transmission instruments		18		2
Settlements		(41)		(18)
Balance as of September 30	$	23	$	3
Change in unrealized gains or losses relating to
instruments still held at September 30	$	―	$	―

Non-Recurring Fair Value Measures Table

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		Estimated		Fair
		Fair		Value	% of Fair Value		Range of
		Value	Valuation Technique	Hierarchy	Measurement	Inputs Used to Develop Measurement	Inputs
Investment in
Rockies Express		$ 369	Market approach	Level 2	67%	Equity sale offer price	100%
			Probability weighted	Level 3	33%	Combined transportation rate assumption(1)	6% - 78%
			discounted cash flow			Counterparty credit risk on existing contracts	Low
						Operation and maintenance escalation rate	0% - 1%
						Forecasted interest rate on debt to be refinanced	5% - 10%
						Discount rate	8% - 10%
Investment in
RBS Sempra
Commodities		$ 126	Discounted cash flow	Level 3	100%	Future cash distributions	90% - 110%
(1)	Transportation rate beyond existing contract terms as a percentage of current mean REX rates.

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GENERAL (Tables)

3 Months Ended

Sep. 30, 2012

General (Tables) [Abstract]

Schedule Of Effective Change In Accounting Principle [Text Block]

EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions, except per share amounts)
		Three months ended September 30, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
Income tax expense		$	68	$	7	$	75
Net income			326		(7)		319
Earnings			296		(7)		289
Basic earnings per common share		$	1.23	$	(0.02)	$	1.21
Diluted earnings per common share		$	1.22	$	(0.02)	$	1.20
		Nine months ended September 30, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
Depreciation and amortization		$	730	$	(1)	$	729
Income before income taxes and equity earnings
of certain unconsolidated subsidiaries			1,316		1		1,317
Income tax expense			269		20		289
Net income			1,092		(19)		1,073
Earnings			1,065		(19)		1,046
Basic earnings per common share		$	4.44	$	(0.08)	$	4.36
Diluted earnings per common share		$	4.40	$	(0.08)	$	4.32
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
Net income		$	1,092	$	(19)	$	1,073
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization			730		(1)		729
Deferred income taxes and investment tax credits			224		(13)		211
Net change in other working capital components (income taxes)			(108)		33		(75)
		As of December 31, 2011
			As
			Originally				Retrospectively
			Reported		Adjustments		Adjusted
CONDENSED CONSOLIDATED BALANCE SHEET
Property, plant and equipment		$	31,303	$	(111)	$	31,192
Less accumulated depreciation and amortization			(7,731)		4		(7,727)
Property, plant and equipment, net		$	23,572	$	(107)	$	23,465
Income taxes payable		$	16	$	(11)	$	5
Deferred income taxes, noncurrent liability			1,554		(34)		1,520
Deferred credits and other			773		1		774
Retained earnings(1)			8,225		(63)		8,162
(1)	Adjustment includes the cumulative effect of the change in accounting principle of reductions in net income and earnings of $26 million, $30 million, a negligible amount, and $7 million for the years ended December 31, 2011, 2010, 2009 and 2008, respectively.

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CALIFORNIA UTILITIES' REGULATORY MATTERS

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Sempra Utilities' Regulatory Matters

NOTE 9. CALIFORNIA UTILITIES' REGULATORY MATTERS

JOINT MATTERS

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. In December 2010, the California Utilities filed their 2012 General Rate Case (GRC) applications to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements will change on an annual basis over the subsequent three-year (2013-2015) period. Both SDG&E and SoCalGas filed revised applications with the CPUC in July 2011. Evidentiary hearings were completed in January 2012, and final briefs reflecting the results from these hearings were filed with the CPUC in May 2012.

In February 2012, the California Utilities filed amendments to update their July 2011 revised applications. With these amendments, SDG&E is requesting a revenue requirement in 2012 of $1.849 billion, an increase of $235 million (or 14.6%) over 2011, of which $67 million is being requested for cost recovery of the incremental wildfire insurance premiums which are not included in the 2011 revenue requirement as set forth in the 2008 GRC. SoCalGas is requesting a revenue requirement in 2012 of $2.112 billion, an increase of $268 million (14.5%) over 2011. The Division of Ratepayer Advocates (DRA)is recommending that the CPUC reduce the utilities' revenue requirements in 2012 by approximately 5 percent compared to 2011.

Until such time as a final decision for the 2012 GRC is issued, the California Utilities are recording revenues in 2012 based on levels authorized in 2011plus, for SDG&E, consistent with the recent CPUC decisions for cost recovery for SDG&E's incremental wildfire insurance premiums, an amount for the recovery of 2012 wildfire insurance premiums. The current CPUC schedule indicates a final decision for the 2012 GRC, which will be made effective retroactive to January 1, 2012, by the end of 2012. However, if the CPUC does not issue a final decision for the 2012 GRC by December 31, 2012, Sempra Energy and the California Utilities will not be able to report the retroactive impact to January 1, 2012 of the final decision in their 2012 financial results, but would reflect the impact in 2013 financial results in the period in which such final decision is issued.

Cost of Capital

A cost of capital proceeding determines a utility's authorized capital structure and authorized rate of return on rate base (ROR), which is a weighted average of the authorized returns on debt, preferred stock, and common equity (return on equity or ROE). The authorized ROR is the rate that the California Utilities are authorized to use in establishing rates to recover their cost of debt and equity, used to finance their investment in electric and natural gas distribution, natural gas transmission and electric generation assets. In addition, a cost of capital proceeding also addresses the automatic ROR adjustment mechanism which applies market-based benchmarks to determine whether an adjustment to the authorized ROR is required during the interim years between cost of capital proceedings.

SDG&E and SoCalGas filed separate applications with the CPUC in April 2012 to update their cost of capital effective January 1, 2013. Southern California Edison (Edison) and Pacific Gas and Electric Company (PG&E) also filed separate cost of capital applications with the CPUC. SDG&E proposes to adjust its authorized capital structure by increasing the amount of its common equity from 49.0 percent to 52.0 percent. SDG&E also proposes to lower its authorized ROE from 11.1 percent to 11.0 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized ROR from 8.40 percent to 8.15 percent. SoCalGas proposes to adjust its authorized capital structure by increasing the amount of its common equity from 48.0 percent to 52.0 percent. SoCalGas also proposes to increase its authorized ROE from 10.82 percent to 10.9 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized ROR from 8.68 percent to 8.44 percent. In addition, SDG&E proposes to continue its currently approved cost of capital adjustment mechanism which uses a utility bond benchmark. SoCalGas proposes switching from its current cost of capital adjustment mechanism, which is based on U.S. Treasury Bonds, to a mechanism using a utility bond benchmark similar to SDG&E, Edison and PG&E. Both SDG&E and SoCalGas are proposing to add an “off ramp” provision to the adjustment mechanism as a safeguard to protect against extreme changes in interest rates and to allow the CPUC latitude to suspend the annual mechanism if prudent.

The CPUC issued a ruling in June 2012 bifurcating the proceeding. Phase 1 will address each utility's cost of capital for 2013 with a final decision expected by the end of 2012. Phase 2 will address the cost of capital adjustment mechanisms for SDG&E, SoCalGas, Edison and PG&E, with a final decision expected in the first half of 2013.

SDG&E's current cost of capital adjustment mechanism benchmark is based on the 12-month average monthly A-rated utility bond yield as published by Moody's for the 12-month period October through September of each fiscal year. If the 12-month average falls outside of a specified range, then SDG&E's authorized ROE would be adjusted, upward or downward, by one-half of the difference between the 12-month average and the mid-point of the specified range. In addition, SDG&E's authorized recovery rate for the cost of debt and preferred stock would also be adjusted to their respective actual weighted average cost. Therefore, SDG&E's authorized ROR would adjust, upward or downward, as a result of all three adjustments with the new rate going into effect on January 1 following the year in which the benchmark range was exceeded. SDG&E's current mechanism only applies during the intervening years between scheduled cost of capital updates and does not apply for any change in 2013 given the pending cost of capital application and the expectation of an updated cost of capital effective as of January 1, 2013.

SoCalGas' Market Indexed Capital Adjustment Mechanism (MICAM) identifies two conditions for determining whether a change in the authorized rate of return is required. Both conditions are based on the 30-year Treasury bond yields – one being the most recent trailing 12-month rolling average yield and the second being the corresponding 12-month forward forecast yield as published by Global Insight. If both conditions fall outside a specified range in a given month, SoCalGas' authorized ROE would be adjusted, upward or downward, by one-half of the difference between the trailing 12-month rolling average yield and the midpoint of the range, effective January 1 following the year in which both conditions were exceeded. Also, SoCalGas' authorized recovery rate for the cost of debt and preferred stock would be adjusted to their respective actual weighted average cost. Therefore, SoCalGas' authorized ROR would adjust, upward or downward, as a result of all three cost adjustments. In the event of such an event occurring, the benchmark interest rate would be reset to the interest rate in effect at the time it was determined that the benchmark range had been exceeded.

In August 2012, the CPUC issued an administrative ruling that confirmed SoCalGas' participation in Phase 1 of the proceeding and held in abeyance the implementation of SoCalGas' MICAM triggering event to make the ROE and ROR authorized by the CPUC in this proceeding effective on January 1, 2013.

Natural Gas Pipeline Operations Safety Assessments

Various regulatory agencies, including the CPUC, are evaluating natural gas pipeline safety regulations, practices and procedures. In February 2011, the CPUC opened a forward-looking rulemaking proceeding to examine what changes should be made to existing pipeline safety regulations for California natural gas pipelines. The California Utilities are parties to this proceeding.

In June 2011, the CPUC directed SoCalGas, SDG&E, PG&E and Southwest Gas to file comprehensive implementation plans to test or replace all natural gas transmission pipelines that have not been pressure tested. The California Utilities filed their Pipeline Safety Enhancement Plan (PSEP) with the CPUC in August 2011. The proposed safety measures, investments and estimated costs are not included in the California Utilities' 2012 GRC requests discussed above.

In December 2011, the assigned Commissioner to the rulemaking proceeding for the pipeline safety regulations ruled that SDG&E's and SoCalGas' Triennial Cost Allocation Proceeding (TCAP) would be the most logical proceeding to conduct the reasonableness and ratemaking review of the companies' PSEP.

In January 2012, the CPUC Consumer Protection and Safety Division (CPSD) issued a Technical Report of the California Utilities' PSEP.  The report, along with testimony and evidentiary hearings, will be used to evaluate the PSEP in the regulatory process.  Generally, the report found that the PSEP approach to pipeline replacement and pressure testing and other proposed enhancements is reasonable. 

In February 2012, the assigned Commissioner in the TCAP issued a ruling setting a schedule for the review of the SDG&E and SoCalGas PSEP with evidentiary hearings held in August 2012. SDG&E and SoCalGas expect a final decision late in the first half of 2013. In April 2012, the CPUC issued an interim decision in the rulemaking proceeding formally transferring the PSEP to the TCAP and authorizing SDG&E and SoCalGas to establish regulatory accounts to record the incremental costs of initiating the PSEP prior to a final decision on the PSEP. The TCAP proceeding will address the recovery of the costs recorded in the regulatory account.

In April 2012, the CPUC issued a decision expanding the scope of the rulemaking proceeding to incorporate the provisions of California Senate Bill 705, which requires gas utilities to develop and implement a plan for the safe and reliable operation of their gas pipeline facilities. SDG&E and SoCalGas submitted their pipeline safety plans in June 2012. The CPUC must accept, modify or reject the plans by the end of 2012. The CPUC decision also orders the utilities to undergo independent management and financial audits to assure that the utilities are fully meeting their safety responsibilities. CPSD will select the independent auditors and will oversee the audits. A schedule for the audits has not been established.

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 Updated Annual Report.

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.

We provide additional information regarding these incentive mechanisms in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report, and in the updates below.

Energy Efficiency

We expecta final decision on an incentive mechanism for the 2013-2014 program period by the end of 2012. We expect a draft decision on how and if an incentive mechanism should apply to the 2010-2012 program cycle and a final decision on any incentive awards for the 2010-2012 period by the end of 2012.The CPUC issued its latest Order Instituting Rulemaking (OIR) in January 2012 to continue its review of the incentive mechanism.

Natural Gas Procurement

In the first quarter of 2012, the CPUC approved and SoCalGas recorded SoCalGas' application for its Gas Cost Incentive Mechanism (GCIM) award of $6.2 million for natural gas procured for its core customers during the 12-month period ending March 31, 2011.

In June 2012, SoCalGas applied to the CPUC for approval of a GCIM award of $5.4 million for natural gas procured for its core customers during the 12-month period ending March 31, 2012. SoCalGas expects a CPUC decision in the first half of 2013.

SDG&E MATTERS

San Onofre Nuclear Generating Station (SONGS)

SDG&E has a 20-percent ownership interest in San Onofre Nuclear Generating Station (SONGS), a 2,150-MW nuclear generating facility near San Clemente, California. SONGS is operated by Edison and is subject to the jurisdiction of the Nuclear Regulatory Commission (NRC) and the CPUC.

In 2005, the CPUC authorized a project to install four new steam generators in Units 2 and 3 at SONGS and remove and dispose of their predecessor generators. Edison completed the installation of these steam generators in 2010 and 2011 for Units 2 and 3, respectively.In January 2012, a water leak occurred in the Unit 3 steam generator which caused it to be shut down. Edison conducted inspection testing and determined that the water leak was the result of excessive wear from tube-to-tube contact. During a planned maintenance and refueling outage on the Unit 2 steam generators in February 2012, inspections found high levels of unexpected wear in some heat transfer tubes of the Unit 2 steam generators. As of today, both Units 2 and 3 remain offline.

Any remedial action that will permit restart of one or both of the Units will need to be approved by the NRC. In March 2012, the NRC issued a Confirmatory Action Letter (CAL) that required NRC permission to restart Unit 2 and Unit 3 and outlined actions that Edison must complete before permission to restart either Unit may be sought. The NRC could also choose to impose additional inspections and assessment processes that could result in significant costs or additional delay. In October 2012, Edison submitted a plan to the NRC to restart and operate Unit 2 at a reduced power level for five months and then shut it down for further inspection. The plan submitted to the NRC does not address Unit 3. It is not clear at this time whether Unit 3 can be restarted without extensive additional repairs, and Edison has not indicated when it believes Unit 3 may be ready to restart operations. The timing of the restart of either of the Units is dependent upon approval by the NRC. The NRC may employ other procedures before making any determination about whether to grant permission pursuant to the terms of the CAL. It is also possible that one or more amendments to the NRC operating license for SONGS might be required (whether or not as a prerequisite to return a Unit to safe operation). There is no set or predetermined time period for such processes, and, accordingly, there can be no assurance about the length of time the NRC may take to review any request to restart submitted by Edison under the CAL or whether any such request would be granted in whole or in part.

Through September 30, 2012, SDG&E's proportional investment in the steam generators was approximately $180 million. These investment amounts remain subject to CPUC review upon submission of Edison's final costs for the overall project.

During the unscheduled outage at SONGS, SDG&E has procured replacement power, the cost of which is fully recovered in revenues subject to a reasonableness review by the CPUC. Replacement power costs for outages associated with the unscheduled SONGS outage (commencing in 2012 on January 31 for Unit 3 and March 5 for Unit 2) through September 30, 2012 were approximately $54 million. Total replacement power costs will not be known until the Units are returned to service.

Currently, SDG&E is collecting in customer rates its share of the operating costs, depreciation and return on its investment in SONGS. For the nine-month period ended September 30, 2012, SDG&E has recognized (and collected through customer rates) an estimated $153 million of revenue associated with its investment in SONGS and operating costs. At September 30, 2012, SDG&E's weighted average rate base investment in SONGS was approximately $220 million and its net book investment, including construction work in progress and nuclear fuel was $485 million.

In November 2012, the CPUC issued an Order Instituting Investigation (OII) into the SONGS outage pursuant to California Public Utilities Code Section 455.5 to determine whether Edison and SDG&E should remove from customer rates some or all revenue requirement associated with the portion of the facility that is out of service. This OII will consolidate all SONGS issues from related regulatory proceedings and consider the appropriate cost recovery for SONGS, including among other costs, the cost of the steam generator replacement project, replacement power costs, capital expenditures, operation and maintenance costs and seismic study costs. The OII requires that all costs related to SONGS incurred since January 1, 2012 be tracked in a separate memorandum account,with all revenues collected in recovery of such costs subject to refund, and will address the extent to which such revenues, if any, will be required to be refunded to customers.

Under Section 455.5, any determination to adjust rates would be made after hearings are conducted in connection with Edison's next general rate case. If, after investigation and hearings, the CPUC were to require SDG&E to reduce rates as a result of a Unit being out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation. Notwithstanding the requirements of Section 455.5, the CPUC may institute other proceedings relating to the impact of the extended outage at SONGS and its potential effects on rates.

The steam generators were designed and supplied by Mitsubishi Heavy Industries (MHI) and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. On July 18, 2012, the NRC issued a report providing the result of the inspection performed by the Augmented Inspection Team (AIT). The inspection concluded that faulty computer modeling that inadequately predicted conditions in the steam generators at SONGS and manufacturing issues contributed to excessive wear of the components. The most probable causes of the tube-to-tube wear were a combination of higher than predicted thermal/hydraulic conditions and changes in the manufacturing of the Unit 3 steam generators. This report also identified a number of yet unresolved issues that are continuing to be examined. Edison's purchase contract with MHI states that MHI's liability under the purchase agreement is limited to $137 million and excludes consequential damages, defined to include the cost of replacement power. Such limitations in the contract are subject to applicable exceptions. In September 2012, Edison submitted an invoice on behalf of all owners to MHI in the amount of $45 million for certain steam generator repair costs incurred. Edison expects to continue to invoice MHI for any additional costs incurred.

SDG&E is a named insured on the Edison insurance policies covering SONGS. These policies, issued by Nuclear Electric Insurance Limited (NEIL), cover nuclear property and non-nuclear property damage at the SONGS facility, as well as accidental outage insurance. Edison has placed NEIL on notice of potential claims for loss recovery. On October 1, 2012, Edison submitted to NEIL a Partial Proof of Loss on behalf of Edison, SDG&E and the City of Riverside in connection with the outages of SONGS Units 2 and 3. The NEIL policies contain a number of exclusions and limitations that may reduce or eliminate coverage. SDG&E will assist Edison in pursuing claims recoveries from NEIL, as well as warranty claims with MHI, but there is no assurance that SDG&E will recover all or any of its applicable costs pursuant to these arrangements.

In light of the aftermath and the significant safety events at the Fukushima Daiichi nuclear plant in Japan resulting from the earthquake and tsunami in March 2011, the NRC plans to perform additional operation and safety reviews of nuclear facilities in the United States. The lessons learned from the events in Japan and the results of the NRC reviews may materially impact future operations and capital requirements at nuclear facilities in the United States, including the operations and capital requirements at SONGS.

Edison is also addressing a number of other regulatory and performance issues at SONGS, and the NRC has required Edison to take actions to provide greater assurance of compliance by SONGS personnel. Edison continues to implement plans and address the identified issues, however a number of these issues remain outstanding. To the extent that these issues persist, it is likely that additional action will be required by Edison, which may result in increased SONGS operating costs and/or materially adversely impacted operations. Currently, SDG&E is allowed to fully offset its share of SONGS operating costs in revenue. If further action is required, it may result in an increase in SDG&E's Operation and Maintenance expense, with any increase being fully offset in Operating Revenues – Electric.

We provide more information about SONGS in Note 10 and in Notes 6, 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Power Procurement and Resource Planning

Renewable Energy

SDG&E is subject tothe Renewables Portfolio Standard (RPS) Program administered by both the CPUC and the California Energy Commission (CEC), which requires each California utility to procure 33 percent of its annual electric energy requirements from renewable energy sources by 2020, with an average of 20 percent required from January 1, 2011 to December 31, 2013; 25 percent by December 31, 2016; and 33 percent by December 31, 2020. The CPUC began a rulemaking in May 2011 to address the implementation of the 33% RPS Program. We discuss the RPS Program further in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

South Orange County Reliability Enhancement

SDG&E filed an application with the CPUC in May 2012 for a Certificate of Public Convenience and Necessity (CPCN) to construct the South Orange County Reliability Enhancement project. The purpose of the project is to enhance the capacity and reliability of SDG&E's electric service to the south Orange County area. The proposed project primarily includes replacing and upgrading approximately eight miles of transmission lines and rebuilding and upgrading a substation at an existing site. SDG&E expects a final CPUC decision approving the estimated $473 million project in the second half of 2013. SDG&E obtained approval for the project from the ISO in May 2011. The project is planned to be in service by the second half of 2017.

Incremental Insurance Premium Cost Recovery

In December 2010, the CPUC approved SDG&E's request for a $29 million revenue requirement for the recovery of the incremental increase in its general liability and wildfire liability insurance premium costs for the July 2009/June 2010 policy period. In its decision approving this cost recovery, the CPUC also authorized SDG&E to request recovery of any incremental insurance premiums for future policy periods through December 31, 2011, with a $5 million deductible applied to each policy renewal period. This approval was in response to a request filed by SDG&E with the CPUC in August 2009 seeking authorization to recover higher liability insurance premiums (amounts in excess of those authorized to be recovered in the 2008 GRC), which SDG&E began incurring commencing July 1, 2009, and any losses realized due to higher deductibles associated with the new policies. SDG&E made the filing under the CPUC's rules allowing utilities to seek recovery of significant cost increases incurred between GRC filings that meet certain criteria, subject to a $5 million deductible per event.

In December 2011, the CPUC approved SDG&E's request for an incremental revenue requirement of $63 million for the July 2010/June 2011 policy period. In May 2012, the CPUC approved SDG&E's request for a $28 million revenue requirement for the first six months of the July 2011/June 2012 policy period.

In the CPUC's December 2010 decision, discussed above, the CPUC directed SDG&E to include in its 2012 GRC application the amount of the incremental wildfire insurance premiums it would be seeking recovery for in rates subsequent to December 31, 2011. SDG&E's 2012 GRC application does request $67 million of revenue requirement for cost recovery of wildfire insurance premiums in 2012. As a decision on SDG&E's 2012 GRC application is pending with the CPUC, and based on the CPUC's rulings for the recovery of the cost of the incremental wildfire insurance premiums incurred since July 2009, SDG&E's 2012 revenue through September 30, 2012 reflects the expected recovery of the cost of the incremental wildfire insurance premiums incurred in the current year.

Excess Wildfire Claims Cost Recovery

SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC in August 2009 proposing a new mechanism for the future recovery of all wildfire-related expenses for claims, litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC for recovery in distribution rates. This application was made jointly with Edison and PG&E. In July 2010, the CPUC approved SDG&E's and SoCalGas' requests for separate regulatory memorandum accounts to record the subject expenses while the application is pending before the CPUC. Several parties protested the original application and, in response, the four utilities jointly submitted an amended application in August 2010. In November 2011, Edison and PG&E requested to withdraw from the joint utility application due, in part, to the delays in the proceeding. In January 2012, the CPUC granted their requests to withdraw and held evidentiary hearings for SDG&E and SoCalGas, both of which are still moving forward with the application. Legal briefs were completed in March 2012.

In October 2012, the Administrative Law Judge's (ALJ) draft decision (Proposed Decision or PD) and the Assigned Commissioner's alternate draft decision (Alternate Decision or AD) in this proceeding were issued. The PD rejects SDG&E's and SoCalGas' request for a new balancing account and cost recovery mechanism and directs both SDG&E and SoCalGas to close the regulatory memorandum account that was previously authorized by the CPUC in July 2010 and remove any amount recorded to it. The PD does, however, state that should SDG&E continue to pursue recovery of such costs incurred, there are other established mechanisms that SDG&E can utilize to seek recovery. The AD approves SDG&E's and SoCalGas' request for a new balancing account and cost recovery mechanism but only for wildfire events that occur after July 2010, the effective date of the CPUC decision authorizing the regulatory memorandum account. The AD also directs SDG&E to remove any amounts recorded in the regulatory memorandum account associated with the 2007 wildfires. Under the terms of the AD, for wildfires for which the utility is found not to be at fault, SDG&E and SoCalGas may seek recovery in rates of 90 percent of costs incurred for payments made to settle claims associated with inverse condemnation which exceed the sum of $10 million per wildfire,theirinsurance coverage, and recoveries made from other third parties. For any costs incurred for wildfire events occurring prior to July 2010, the AD allows the utility to use the existing Z-factor application process to request recovery of such costs. A Z-factor application process allows utilities to seek recovery of significant cost increases incurred between GRC filings. We expect a final CPUC decision in the current proceeding by the end of 2012.

Following the issuance of the PD and the AD and consistent with CPUC rules and procedures, SDG&E requested an ex parte meeting with the Assigned Commissioner and staff. The request was granted, and the ex parte meeting was held on October 29, 2012. At the meeting, SDG&E provided information to the Assigned Commissioner addressing key issues from the AD that SDG&E believes contradict prior CPUC rulings and decisions. On November 5, 2012, SDG&E provided the CPUC with written comments and suggested changes to the AD. While there can be no assurance that the Assigned Commissioner will amend the AD, given the relevant regulatory and statutory standards and the issues discussed at the ex parte meeting, SDG&E has concluded that it remains probable that SDG&E will be permitted to recover from ratepayers substantially all reasonably incurred costs associated with the 2007 wildfires that exceed amounts recovered from its insurance coverage and other responsible third parties. SDG&E intends to continue to pursue recovery of such costs in this proceeding or, if necessary, in a future application, such as the Z-factor application noted in both the PD and the AD.

SDG&E will continue to assess the recovery of these excess wildfire costs from ratepayers. Should SDG&E conclude that the amount of recovery from ratepayers is no longer reasonably estimable or that recovery is no longer probable, including as a result of the CPUC's failure to adopt a final decision in this proceeding that supports future recovery from ratepayers, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that such recovery was no longer probable or reasonably estimable as of September 30, 2012, the resulting after-tax charge against earnings would have been approximately $175 million. In addition, in periods following any such conclusion, SDG&E's earnings will be adversely impacted by increases in the estimated cost to settle pending wildfire claims.

We provide additional information about 2007 wildfire litigation costs and their recovery in Note 10.

East County Substation

In June 2012, the CPUC approved SDG&E's application for authorization to proceed with the East County Substation project, estimated to cost $435 million. The Bureau of Land Management (BLM) issued its record of decision in August 2012. SDG&E expects to begin construction in the first half of 2013 and the substation to be placed in service in 2014. We provide additional information on the project in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

SOCALGAS MATTER

Aliso Canyon Natural Gas Storage Compressor Replacement

In September 2009, SoCalGas filed an application with the CPUC requesting approval to replace certain obsolete natural gas turbine compressors used in the operations of SoCalGas' Aliso Canyon natural gas storage reservoir, with a new electric compressor station. In April 2012, the CPUC issued a draft environmental impact report (EIR) for the project concluding that no significant or unavoidable adverse environmental impacts have been identified from the construction or operation of the proposed project. We expect a final EIR and CPUC decision on the estimated $200million projectin 2013.

We discuss additional matters affecting our California Utilities in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

XML

SEGMENT INFORMATION (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011		Dec. 31, 2011
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenues	$ 2,507		$ 2,576	[1]	$ 6,979		$ 7,432	[1]
Segment reporting information, Percentage of Total Consolidated Revenues	100.00%		100.00%		100.00%		100.00%
Segment reporting information, Interest Expense	126		118	[1]	352		344	[1]
Segment reporting information, Interest Income	5		6	[1]	14		21	[1]
Segment reporting information, Depreciation and Amortization	280		251	[1]	803		729	[1]
Segment reporting information, Percentage of Consolidated Depreciation and Amortization	100.00%		100.00%		100.00%		100.00%
Segment reporting information, Income Tax Expense (Benefit)	49		75	[1]	48		289	[1]
Segment reporting information, Equity Earnings (Losses) Recorded Before Tax	(94)		(12)	[1]	(375)		(4)	[1]
Segment reporting information, Equity Earnings (Losses) Recorded Net of Tax	10		6	[1]	29		45	[1]
Segment reporting information, earnings (losses)	268		289	[1]	566		1,046	[1]
Segment reporting information, Percentage of Consolidated Earnings (Losses)	100.00%		100.00%		100.00%		100.00%
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Expenditures for Property, Plant & Equipment					2,241		2,031
Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment					100.00%		100.00%
Segment reporting information, Assets	35,390				35,390				33,249	[1],[2]
Segment reporting information, Percentage of Consolidated Assets	100.00%				100.00%				100.00%
Segment Reporting Information Investments In Equity Method Investees	1,503				1,503				1,629
S D G E Segment [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenues	1,092		868		2,706		2,405
Segment reporting information, Percentage of Total Consolidated Revenues	44.00%		34.00%		39.00%		32.00%
Segment reporting information, Interest Expense	49		37		124		104
Segment reporting information, Depreciation and Amortization	128		108		359		316
Segment reporting information, Percentage of Consolidated Depreciation and Amortization	46.00%		43.00%		45.00%		43.00%
Segment reporting information, Income Tax Expense (Benefit)	38		63		151		154
Segment reporting information, earnings (losses)	174	[3]	113	[3]	374	[3]	273	[3]
Segment reporting information, Percentage of Consolidated Earnings (Losses)	65.00%		39.00%		66.00%		26.00%
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Expenditures for Property, Plant & Equipment					998		1,162
Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment					44.00%		57.00%
Segment reporting information, Assets	14,589				14,589				13,555
Segment reporting information, Percentage of Consolidated Assets	41.00%				41.00%				41.00%
Segment Reporting Information, Intersegment Revenue	3		2		6		5
Segment Reporting Information, Intersegment Receivables	17				17				67
So Cal Gas Segment [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenues	728		844		2,328		2,776
Segment reporting information, Percentage of Total Consolidated Revenues	29.00%		33.00%		33.00%		37.00%
Segment reporting information, Interest Expense	17		17		51		52
Segment reporting information, Interest Income			1				1
Segment reporting information, Depreciation and Amortization	91		83		268		246
Segment reporting information, Percentage of Consolidated Depreciation and Amortization	33.00%		33.00%		33.00%		34.00%
Segment reporting information, Income Tax Expense (Benefit)	37		41		105		106
Segment reporting information, earnings (losses)	71	[3]	81	[3]	190	[3]	208	[3]
Segment reporting information, Percentage of Consolidated Earnings (Losses)	26.00%		28.00%		34.00%		20.00%
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Expenditures for Property, Plant & Equipment					462		499
Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment					21.00%		25.00%
Segment reporting information, Assets	8,784				8,784				8,475
Segment reporting information, Percentage of Consolidated Assets	25.00%				25.00%				25.00%
Segment Reporting Information, Intersegment Revenue	17		13		48		38
Segment Reporting Information, Intersegment Receivables	280				280				40
All Other Segments [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Interest Expense	62		58		185		174
Segment reporting information, Interest Income			(2)				1
Segment reporting information, Depreciation and Amortization	3		4		9		11
Segment reporting information, Percentage of Consolidated Depreciation and Amortization	1.00%		2.00%		1.00%		1.00%
Segment reporting information, Income Tax Expense (Benefit)	(17)		(58)		(91)		(100)
Segment reporting information, Equity Earnings (Losses) Recorded Before Tax	(1)		(16)		(2)		(27)
Segment reporting information, earnings (losses)	(16)		(44)		(37)		(102)
Segment reporting information, Percentage of Consolidated Earnings (Losses)	(6.00%)		(15.00%)		(7.00%)		(10.00%)
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Expenditures for Property, Plant & Equipment					3		1
Segment reporting information, Assets	520				520				538
Segment reporting information, Percentage of Consolidated Assets	1.00%				1.00%				2.00%
Segment Reporting Information Investments In Equity Method Investees	135				135				137
Adjustments and Eliminations [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenues			(1)		(1)		(1)
Intercompany Eliminations Segment [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Interest Expense	(44)		(33)		(125)		(95)
Segment reporting information, Interest Income	(19)		(10)		(51)		(31)
Intersegment Revenues Segment [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenues	(171)	[4]	(125)	[4]	(359)	[4]	(372)	[4]
Segment reporting information, Percentage of Total Consolidated Revenues	(7.00%)		(5.00%)		(5.00%)		(5.00%)
Intersegment Receivables Segment [Member]
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Assets	(3,108)	[5]			(3,108)	[5]			(2,162)	[5]
Segment reporting information, Percentage of Consolidated Assets	(9.00%)				(9.00%)				(7.00%)
Sempra South American Utilities Segment [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenues	356		345		1,061		706
Segment reporting information, Percentage of Total Consolidated Revenues	14.00%		13.00%		15.00%		10.00%
Segment reporting information, Interest Expense	6		9		22		23
Segment reporting information, Interest Income	3		6		11		18
Segment reporting information, Depreciation and Amortization	15		14		42		27
Segment reporting information, Percentage of Consolidated Depreciation and Amortization	5.00%		6.00%		5.00%		4.00%
Segment reporting information, Income Tax Expense (Benefit)	27		18		57		30
Segment reporting information, Equity Earnings (Losses) Recorded Net of Tax							23
Segment reporting information, earnings (losses)	40		50		118		386
Segment reporting information, Percentage of Consolidated Earnings (Losses)	15.00%		17.00%		21.00%		37.00%
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Expenditures for Property, Plant & Equipment					117		63
Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment					5.00%		3.00%
Segment reporting information, Assets	3,241				3,241				2,981
Segment reporting information, Percentage of Consolidated Assets	9.00%				9.00%				9.00%
Segment Reporting Information, Intersegment Receivables	54				54				52
Sempra Mexico Segment [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenues	181		183		434		561
Segment reporting information, Percentage of Total Consolidated Revenues	7.00%		7.00%		6.00%		8.00%
Segment reporting information, Interest Expense	4		4		10		15
Segment reporting information, Interest Income	4		3		10		7
Segment reporting information, Depreciation and Amortization	15		15		46		46
Segment reporting information, Percentage of Consolidated Depreciation and Amortization	5.00%		6.00%		6.00%		6.00%
Segment reporting information, Income Tax Expense (Benefit)	21		(7)		44		24
Segment reporting information, Equity Earnings (Losses) Recorded Net of Tax	10		6		29		22
Segment reporting information, earnings (losses)	54		47		134		121
Segment reporting information, Percentage of Consolidated Earnings (Losses)	20.00%		16.00%		24.00%		12.00%
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Expenditures for Property, Plant & Equipment					13		11
Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment					1.00%		1.00%
Segment reporting information, Assets	3,042				3,042				2,914
Segment reporting information, Percentage of Consolidated Assets	9.00%				9.00%				9.00%
Segment Reporting Information Investments In Equity Method Investees	333				333				302
Segment Reporting Information, Intersegment Revenue	78		48		161		157
Segment Reporting Information, Intersegment Receivables	643				643				543
Sempra Renewables Segment [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenues	27		7		49		17
Segment reporting information, Percentage of Total Consolidated Revenues	1.00%				1.00%
Segment reporting information, Interest Expense	6		4		13		9
Segment reporting information, Interest Income	2				3
Segment reporting information, Depreciation and Amortization	4		1		10		4
Segment reporting information, Percentage of Consolidated Depreciation and Amortization	1.00%		0.00%		1.00%		1.00%
Segment reporting information, Income Tax Expense (Benefit)	(12)		(9)		(47)		(22)
Segment reporting information, Equity Earnings (Losses) Recorded Before Tax	(6)		(6)		(7)		(6)
Segment reporting information, earnings (losses)	13		1		47		9
Segment reporting information, Percentage of Consolidated Earnings (Losses)	5.00%		1.00%		8.00%		1.00%
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Expenditures for Property, Plant & Equipment					564		124
Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment					25.00%		6.00%
Segment reporting information, Assets	2,412				2,412				1,210
Segment reporting information, Percentage of Consolidated Assets	7.00%				7.00%				4.00%
Segment Reporting Information Investments In Equity Method Investees	666				666				390
Segment Reporting Information, Intersegment Receivables	521				521				263
Sempra Natural Gas Segment [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Segment reporting information, Revenues	294		455		761		1,340
Segment reporting information, Percentage of Total Consolidated Revenues	12.00%		18.00%		11.00%		18.00%
Segment reporting information, Interest Expense	26		22		72		62
Segment reporting information, Interest Income	15		8		41		25
Segment reporting information, Depreciation and Amortization	24		26		69		79
Segment reporting information, Percentage of Consolidated Depreciation and Amortization	9.00%		10.00%		9.00%		11.00%
Segment reporting information, Income Tax Expense (Benefit)	(45)		27		(171)		97
Segment reporting information, Equity Earnings (Losses) Recorded Before Tax	(87)		10		(366)		29
Segment reporting information, earnings (losses)	(68)		41		(260)		151
Segment reporting information, Percentage of Consolidated Earnings (Losses)	(25.00%)		14.00%		(46.00%)		14.00%
Segment Reporting Information, Additional Information [Abstract]
Segment reporting information, Expenditures for Property, Plant & Equipment					84		171
Segment reporting information, Percentage of Consolidated Expenditures for Property, Plant & Equipment					4.00%		8.00%
Segment reporting information, Assets	5,910				5,910				5,738
Segment reporting information, Percentage of Consolidated Assets	17.00%				17.00%				17.00%
Segment Reporting Information Investments In Equity Method Investees	369				369				800
Segment Reporting Information, Intersegment Revenue	73		62		144		172
Segment Reporting Information, Intersegment Receivables	$ 1,600				$ 1,600				$ 1,200

[1] As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

[2] Derived from audited financial statements.

[3] After preferred dividends.

[4] Revenues for reportable segments include intersegment revenues of: $3 million, $17 million, $78 million and $73 million for the three months ended September 30, 2012; $6 million, $48 million, $161 million and $144 million for the nine months ended September 30, 2012; $2 million, $13 million, $48 million and $62 million for the three months ended September 30, 2011; and $5 million, $38 million, $157 million and $172 million for the nine months ended September 30, 2011 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.

[5] Assets for reportable segments include intersegment receivables of: $17 million, $280 million, $54 million, $643 million, $521 million, and $1.6 billion at September 30, 2012; and $67 million, $40 million, $52 million, $543 million, $263 million, and $1.2 billion at December 31, 2011 for SDG&E, SoCalGas, Sempra South American Utilities, Sempra Mexico, Sempra Renewables and Sempra Natural Gas, respectively.

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DERIVATIVE FINANCIAL INSTRUMENTS

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Derivative Financial Instruments

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) thatcould 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 (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 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 instruments 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.

• The California Utilities use natural gas energy derivatives, on their customers' behalf, with the objective of managing price risk and basis risks, and lowering natural gas costs. These derivatives include fixed price natural gas positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments. This activity is governed by risk management and transacting activity plans that have been filed with and approved by theCPUC. Natural gas 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, tooptimize the earnings of theirassets 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 as of September 30, 2012 and December 31, 2011 as follows:

Segment and Commodity		September 30, 2012	December 31, 2011
California Utilities:
SDG&E:
Natural gas		23 million MMBtu	35 million MMBtu	(1)
Congestion revenue rights		18 million MWh	19 million MWh	(2)
Energy-Related Businesses:
Sempra Natural Gas:
Electric power		2 million MWh	5 million MWh
Natural gas		32 million MMBtu	20 million MMBtu
Sempra Mexico - natural gas		1 million MMBtu	1 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 our customers, assets and other contractual obligations, 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, which are 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. 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 natural gas derivatives. Accordingly, interest rate derivatives are generally accounted for as hedges at the California Utilities, as well as at the rest of Sempra Energy's subsidiaries. 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.

The net notional amounts of our interest rate derivatives as of September 30, 2012and December 31, 2011were:

		September 30, 2012			December 31, 2011
(Dollars in millions)		Notional Debt		Maturities	Notional Debt		Maturities
Sempra Energy Consolidated(1)		$	6-369	2013-2028	$	15-305	2013-2019
SDG&E(1)			285-347	2019		285-355	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 primarily as a result of our Mexican subsidiaries, which have U.S. dollar denominated 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 short-term 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.

FINANCIAL STATEMENT PRESENTATION

The following tables provide the fair values of derivative instruments, without consideration of margin deposits held or posted,on the Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011:

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		September 30, 2012
									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 designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Interest rate instruments(3)		$	6	$	15	$	(20)	$	(69)
Commodity contracts not subject to rate recovery			―		―		(3)		―
Total		$	6	$	15	$	(23)	$	(69)
SDG&E:
Interest rate instruments(3)		$	―	$	―	$	(17)	$	(68)
Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
Interest rate and foreign exchange instruments		$	8	$	43	$	(8)	$	(38)
Commodity contracts not subject to rate recovery			119		19		(131)		(31)
Associated offsetting commodity contracts			(111)		(15)		111		15
Commodity contracts subject to rate recovery			9		20		(39)		(7)
Associated offsetting commodity contracts			(5)		(1)		5		1
Total		$	20	$	66	$	(62)	$	(60)
SDG&E:
Commodity contracts subject to rate recovery		$	7	$	20	$	(37)	$	(7)
Associated offsetting commodity contracts			(4)		(1)		4		1
Total		$	3	$	19	$	(33)	$	(6)
SoCalGas:
Commodity contracts subject to rate recovery		$	2	$	―	$	(2)	$	―
Associated offsetting commodity contracts			(1)		―		1		―
Total		$	1	$	―	$	(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.
DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		December 31, 2011
									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 designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
Interest rate instruments(3)		$	5	$	11	$	(17)	$	(65)
SDG&E:
Interest rate instruments(3)		$	―	$	―	$	(16)	$	(65)
Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
Interest rate instruments		$	8	$	41	$	(7)	$	(36)
Commodity contracts not subject to rate recovery			156		72		(148)		(94)
Associated offsetting commodity contracts			(120)		(68)		120		68
Commodity contracts subject to rate recovery			28		8		(62)		(24)
Associated offsetting commodity contracts			(10)		(2)		10		2
Total		$	62	$	51	$	(87)	$	(84)
SDG&E:
Commodity contracts subject to rate recovery		$	22	$	8	$	(55)	$	(24)
Associated offsetting commodity contracts			(5)		(2)		5		2
Total		$	17	$	6	$	(50)	$	(22)
SoCalGas:
Commodity contracts subject to rate recovery		$	6	$	―	$	(7)	$	―
Associated offsetting commodity contracts			(5)		―		5		―
Total		$	1	$	―	$	(2)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

The effects of derivative instruments designated as hedges on theCondensed Consolidated Statements of Operations and on Other Comprehensive Income (OCI) and Accumulated Other Comprehensive Income (AOCI) for the three months andnine months endedSeptember 30were:

FAIR VALUE HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
			Gain on derivatives recognized in earnings				Gain (loss) on derivatives recognized in earnings
			Three months ended September 30,				Nine months ended September 30,
		Location	2012		2011		2012		2011
Sempra Energy Consolidated:
Interest rate instruments		Interest Expense	$	1	$	2	$	5	$	7
Interest rate instruments		Other Income, Net		4		13		6		16
Total(1)			$	5	$	15	$	11	$	23
SoCalGas:
Interest rate instrument		Interest Expense	$	―	$	―	$	―	$	1
Interest rate instrument		Other Income, Net		―		―		―		(3)
Total(1)			$	―	$	―	$	―	$	(2)
(1)	There has been no hedge ineffectiveness on these swaps. Changes in the fair values of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt.

CASH FLOW HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
		Pretax loss recognized					Gain (loss) reclassified from AOCI
		in OCI (effective portion)					into earnings (effective portion)
		Three months ended September 30,					Three months ended September 30,
		2012		2011		Location	2012		2011
Sempra Energy Consolidated:
Interest rate instruments(1)		$	(6)	$	(21)	Interest Expense	$	(3)	$	4
						Equity Losses,
Interest rate instruments			(6)		(27)	Before Income Tax		(4)		(2)
Commodity contracts not subject						Cost of Natural Gas, Electric
to rate recovery			(3)		―	Fuel and Purchased Power		―		―
Total		$	(15)	$	(48)		$	(7)	$	2
SDG&E:
Interest rate instruments(1)		$	(6)	$	(21)	Interest Expense	$	(2)	$	4
SoCalGas:
Interest rate instruments		$	―	$	―	Interest Expense	$	(1)	$	(1)
		Nine months ended September 30,					Nine months ended September 30,
		2012		2011		Location	2012		2011
Sempra Energy Consolidated:
Interest rate instruments(1)		$	(21)	$	(32)	Interest Expense	$	(5)	$	―
						Equity Losses,
Interest rate instruments			(12)		(34)	Before Income Tax		(4)		(3)
Commodity contracts not subject						Cost of Natural Gas, Electric
to rate recovery			(3)		―	Fuel and Purchased Power		―		―
Total		$	(36)	$	(66)		$	(9)	$	(3)
SDG&E:
Interest rate instruments(1)		$	(16)	$	(32)	Interest Expense	$	(3)	$	2
SoCalGas:
Interest rate instruments		$	―	$	―	Interest Expense	$	(2)	$	(3)
(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. There has been a negligible amount of ineffectiveness related to these swaps.

Sempra Energy expects that losses of $18 million, which are net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts that are currently outstanding mature.

SDG&E and SoCalGas expect that losses of $8million and $1 million, respectively, which are net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings.

For all forecasted transactions, the maximum term over which we are hedging exposure to the variability of cash flows at September 30, 2012 is approximately 17 years and 7 years forSempra Energy and SDG&E, respectively. The maximum term of hedged interest rate variability related to debt at Sempra Renewables' equity method investees is 18 years.

We recorded $1 million of hedge ineffectiveness in boththe three months and nine months ended September 30, 2012.

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

UNDESIGNATED DERIVATIVE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
		Gain (loss) on derivatives recognized in earnings
		Three months ended September 30,				Nine months ended September 30,
	Location	2012		2011		2012		2011
Sempra Energy Consolidated:
Interest rate and foreign exchange
instruments	Other Income, Net	$	1	$	(26)	$	11	$	(14)
Commodity contracts not subject	Revenues: Energy-Related
to rate recovery	Businesses		(5)		3		(3)		17
Commodity contracts not subject	Cost of Natural Gas, Electric
to rate recovery	Fuel and Purchased Power		―		―		―		1
Commodity contracts not subject
to rate recovery	Operation and Maintenance		1		―		1		1
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power		41		(15)		32		(6)
Commodity contracts subject
to rate recovery	Cost of Natural Gas		―		(2)		(1)		(1)
Total		$	38	$	(40)	$	40	$	(2)
SDG&E:
Commodity contracts not subject
to rate recovery	Operation and Maintenance	$	―	$	(1)	$	―	$	―
Commodity contracts subject	Cost of Electric Fuel
to rate recovery	and Purchased Power		41		(15)		32		(6)
Total		$	41	$	(16)	$	32	$	(6)
SoCalGas:
Commodity contracts not subject
to rate recovery	Operation and Maintenance	$	1	$	(1)	$	1	$	―
Commodity contracts subject
to rate recovery	Cost of Natural Gas		―		(2)		(1)		(1)
Total		$	1	$	(3)	$	―	$	(1)

CONTINGENT FEATURES

For Sempra Energy and SDG&E, certain of our derivative instruments contain credit limits which vary depending upon 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 and SDG&E, the total fair value of this group of derivative instruments in a net liability position at September 30, 2012 is $11 million and $6 million, respectively. As of September 30, 2012, if the credit ratings of Sempra Energy and SDG&E were reduced below investment grade, $11 million and $6 million, respectively, of additional assets could be required to be posted as collateral for these derivative contracts.

For Sempra Energy, SDG&Eand 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.

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FAIR VALUE MEASUREMENTS

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Fair Value Measurements

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 Notes 1 and 2 of the Notes to Consolidated Financial Statements in the Updated Annual Report. We have not changed the valuation techniques or inputs we use to measure fair value during the nine months ended September 30, 2012.

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 as of September 30, 2012 and December 31, 2011.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 determined in accordance with our netting policy, as discussed below under “Derivative Positions Net of Cash Collateral.”

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 as of September 30, 2012 and December 31, 2011 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 assetsusing 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 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). All Level 3 recurring items are related to CRRs at SDG&E, as discussed below under “Level 3 Information.” Commodity derivative contracts that are subject to rate recovery are recorded 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.

RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		At fair value as of September 30, 2012
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	529	$	―	$	―	$	―	$	529
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			72		74		―		―		146
Municipal bonds			―		66		―		―		66
Other securities			―		123		―		―		123
Total debt securities			72		263		―		―		335
Total nuclear decommissioning trusts(1)			601		263		―		―		864
Interest rate instruments			―		73		―		―		73
Commodity contracts subject to rate recovery			21		―		23		―		44
Commodity contracts not subject to rate recovery			19		19		―		―		38
Investments			1		―		―		―		1
Total		$	642	$	355	$	23	$	―	$	1,020
Liabilities:
Interest rate and foreign exchange instruments		$	―	$	136	$	―	$	―	$	136
Commodity contracts subject to rate recovery			32		8		―		(32)		8
Commodity contracts not subject to rate recovery			9		30		―		(13)		26
Total		$	41	$	174	$	―	$	(45)	$	170
		At fair value as of December 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	468	$	―	$	―	$	―	$	468
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			92		78		―		―		170
Municipal bonds			―		77		―		―		77
Other securities			―		78		―		―		78
Total debt securities			92		233		―		―		325
Total nuclear decommissioning trusts(1)			560		233		―		―		793
Interest rate instruments			―		66		―		―		66
Commodity contracts subject to rate recovery			10		1		23		―		34
Commodity contracts not subject to rate recovery			15		35		―		(2)		48
Investments			5		―		―		―		5
Total		$	590	$	335	$	23	$	(2)	$	946
Liabilities:
Interest rate instruments		$	1	$	124	$	―	$	―	$	125
Commodity contracts subject to rate recovery			61		13		―		(61)		13
Commodity contracts not subject to rate recovery			1		52		―		(4)		49
Total		$	63	$	189	$	―	$	(65)	$	187
(1)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
		At fair value as of September 30, 2012
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	529	$	―	$	―	$	―	$	529
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			72		74		―		―		146
Municipal bonds			―		66		―		―		66
Other securities			―		123		―		―		123
Total debt securities			72		263		―		―		335
Total nuclear decommissioning trusts(1)			601		263		―		―		864
Commodity contracts subject to rate recovery			19		―		23		―		42
Commodity contracts not subject to rate recovery			2		―		―		―		2
Total		$	622	$	263	$	23	$	―	$	908
Liabilities:
Interest rate instruments		$	―	$	85	$	―	$	―	$	85
Commodity contracts subject to rate recovery			32		7		―		(32)		7
Total		$	32	$	92	$	―	$	(32)	$	92
		At fair value as of December 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts:
Equity securities		$	468	$	―	$	―	$	―	$	468
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			92		78		―		―		170
Municipal bonds			―		77		―		―		77
Other securities			―		78		―		―		78
Total debt securities			92		233		―		―		325
Total nuclear decommissioning trusts(1)			560		233		―		―		793
Commodity contracts subject to rate recovery			9		―		23		―		32
Commodity contracts not subject to rate recovery			1		―		―		―		1
Total		$	570	$	233	$	23	$	―	$	826
Liabilities:
Interest rate instruments		$	―	$	81	$	―	$	―	$	81
Commodity contracts subject to rate recovery			61		12		―		(61)		12
Total		$	61	$	93	$	―	$	(61)	$	93
(1)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
	At fair value as of September 30, 2012
								Collateral
		Level 1		Level 2		Level 3		netted		Total
Assets:
Commodity contracts subject to rate recovery	$	2	$	―	$	―	$	―	$	2
Commodity contracts not subject to rate recovery		2		―		―		―		2
Total	$	4	$	―	$	―	$	―	$	4
Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
Total	$	―	$	1	$	―	$	―	$	1
	At fair value as of December 31, 2011
								Collateral
		Level 1		Level 2		Level 3		netted		Total
Assets:
Commodity contracts subject to rate recovery	$	1	$	1	$	―	$	―	$	2
Commodity contracts not subject to rate recovery		2		―		―		―		2
Total	$	3	$	1	$	―	$	―	$	4
Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
Total	$	―	$	1	$	―	$	―	$	1

Level 3 Information

The following table sets forth reconciliations of changes in the fair value of CRRs classified as Level 3 in the fair value hierarchyfor Sempra Energy Consolidated and SDG&E:

	Three months ended September 30,
(Dollars in millions)	2012		2011
Balance as of July 1	$	13	$	3
Realized and unrealized gains		16		5
Allocated transmission instruments		17		―
Settlements		(23)		(5)
Balance as of September 30	$	23	$	3
Change in unrealized gains or losses relating to
instruments still held at September 30	$	―	$	―

	Nine months ended September 30,
(Dollars in millions)	2012		2011
Balance as of January 1	$	23	$	2
Realized and unrealized gains		23		17
Allocated transmission instruments		18		2
Settlements		(41)		(18)
Balance as of September 30	$	23	$	3
Change in unrealized gains or losses relating to
instruments still held at September 30	$	―	$	―

CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California Independent System Operator (ISO), an objective source. The impact associated with discounting is negligible. Because auction prices are a less observable input, these instruments are classified as Level 3. Auction prices range from $(3) per MWh to $5 per MWh at a given location, and 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. The earnings impacts of CRRs are deferred and recorded in regulatory accounts to the extent they are recoverable or refundable through rates. Upon settlement, CRRs are included in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations.

Derivative Positions Net of Cash Collateral

Each Condensed Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when management believes a legal right of offset exists.

The following table provides the amount of fair value of cash collateral receivables that were not offset in the Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011:

	September 30,		December 31,
(Dollars in millions)	2012		2011
Sempra Energy Consolidated	$	46	$	20
SDG&E		20		10
SoCalGas		4		2

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. The following table provides the carrying amounts and fair values of certain other financial instruments at September 30, 2012 and December 31, 2011:

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
		September 30, 2012
		Carrying		Fair Value
		Amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Investments in affordable housing partnerships(1)		$	16	$	―	$	―	$	46	$	46
Total long-term debt(2)			11,727		―		12,556		755		13,311
Preferred stock of subsidiaries			99		―		108		―		108
SDG&E:
Total long-term debt(3)		$	4,137	$	―	$	4,308	$	347	$	4,655
Contingently redeemable preferred stock			79		―		86		―		86
SoCalGas:
Total long-term debt(4)		$	1,662	$	―	$	1,872	$	―	$	1,872
Preferred stock			22		―		24		―		24
		December 31, 2011
		Carrying		Fair Value
		Amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Investments in affordable housing partnerships(1)		$	21	$	―	$	―	$	48	$	48
Total long-term debt(2)			9,826		―		10,447		600		11,047
Preferred stock of subsidiaries			99		―		106		―		106
SDG&E:
Total long-term debt(3)		$	3,895	$	―	$	3,933	$	355	$	4,288
Contingently redeemable preferred stock			79		―		86		―		86
SoCalGas:
Total long-term debt(4)		$	1,313	$	―	$	1,506	$	―	$	1,506
Preferred stock			22		―		23		―		23
(1)	We discuss our investments in affordable housing partnerships in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
(2)	Before reductions for unamortized discount (net of premium) of $17 million at September 30, 2012 and $16 million at December 31, 2011, and excluding capital leases of $192 million at September 30, 2012 and $204 million at December 31, 2011, and commercial paper classified as long-term debt of $400 million at December 31, 2011. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
(3)	Before reductions for unamortized discount of $12 million at September 30, 2012 and $11 million at December 31, 2011, and excluding capital leases of $187 million at September 30, 2012 and $193 million at December 31, 2011.
(4)	Before reductions for unamortized discount of $4 million at September 30, 2012 and $3 million at December 31, 2011, and excluding capital leases of $5 million at September 30, 2012 and $11 million at December 31, 2011.

We calculate the fair value of our investments in affordable housing partnerships using an income approach based onthe present value of estimated future cash flows discounted at rates available for similar investments (Level 3).

We base the fair value of certain of ourlong-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).

Nuclear Decommissioning Trusts

We discuss SDG&E's investments in nuclear decommissioning trust funds in Note 6 of the Notes to Consolidated Financial Statements in the Updated Annual Report. The following table shows the fair values and gross unrealized gains and losses for the securities held in the trust funds:

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
			Cost		Gains		Losses		Value
As of September 30, 2012:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies(1)		$	134	$	12	$	―	$	146
Municipal bonds(2)			60		6		―		66
Other securities(3)			114		9		―		123
Total debt securities			308		27		―		335
Equity securities			249		284		(4)		529
Cash and cash equivalents			28		―		―		28
Total		$	585	$	311	$	(4)	$	892
As of December 31, 2011:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		$	157	$	13	$	―	$	170
Municipal bonds			72		5		―		77
Other securities			76		3		(1)		78
Total debt securities			305		21		(1)		325
Equity securities			246		227		(5)		468
Cash and cash equivalents			11		―		―		11
Total		$	562	$	248	$	(6)	$	804
(1)	Maturity dates are 2013-2042
(2)	Maturity dates are 2012-2057
(3)	Maturity dates are 2013-2111

The following table shows the proceeds from sales of securities in the trusts 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,
	2012		2011		2012		2011
Proceeds from sales	$	204	$	294	$	524	$	384
Gross realized gains		3		27		12		29
Gross realized losses		(1)		(8)		(6)		(10)

Net unrealized gains (losses) are included in Regulatory Liabilities Arising from Removal Obligations on the Condensed Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.

Non-Recurring Fair Value Measures – Sempra Energy Consolidated

We discuss non-recurring fair value measures and the associated accounting impact on our investments in RBS Sempra Commodities and Argentina in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report and, with regard to RBS Sempra Commodities, in Note 4 above. We also discuss non-recurring fair value measures and the associated accounting impact on our investment in Rockies Express in Note 4 above.

Rockies Express

In the second quarter of 2012, the noncash impairment charge of $300 million ($179 million after-tax) primarily resulted from the continuing decline in basis differential on REX associated with shale gas production zones coming on line, assumptions related to the re-contracting of the long-term transportation agreements, and the refinancing of the existing project level debt, discussed further below. The fair value measurement was significantly impacted by unobservable inputs (Level 3) as defined by the accounting guidance for fair value measurements, which we discuss in Note 11 of the Notes to Consolidated Financial Statements in the Updated Annual Report. We considered a market participant's view of the total value for Rockies Express, based on an estimation of the future cash distributions it would be able to generate, adjusted for our 25-percent ownership interest. To estimate future cash distributions, we considered factors impacting Rockies Express' ability to pay future distributions including:

• the extent to which future cash flows are hedged by capacity sales contracts and their duration (generally through 2019), as well as the creditworthiness of the various counterparties;
• Rockies Express' future financing needs, including the ability to secure borrowings at reasonable rates as well as potentially using operating cash to retire principal;
• prospects for generating attractive revenues and cash flows beyond 2019, including natural gas' future basis differentials (driven by the location and extent of future supply and demand) and alternative strategies potentially available to utilize the assets; and

• discount rates commensurate with the risks inherent in the cash flows.

In the third quarter of 2012, KMI reached an agreement, expected to close in the fourth quarter of 2012, to sell the FTC-mandated asset group, which includes its interest in Rockies Express. Events in the third quarter of 2012 related to this agreement have provided us with additional market participant data. We therefore updated our analysis of the fair value of our investment in Rockies Express as of September 30, 2012 to reflect these additional inputs and recorded an additional impairment charge of $100 million ($60 million after-tax). This fair value measurement in the third quarter was based primarily on the Level 2 input. We believe this is useful and reliable information, but we considered that it may be impacted by the FTC's requirement for KMI to sell its interest in Rockies Express. To reflect this uncertainty, our updated analysis included the less subjective Level 2 market participant input as the primary indicator of fair value, with less weight ascribed to value based on estimated discounted cash flows as discussed above and in the table below. The updates to the cash flow analyses used in determining fair value in the second quarter reflecteddiscussions with Tallgrass as to the strategic direction they are planning to take with their equity partners for Rockies Express, as well as additional discussions with other market participants. Tallgrass is expected to be the operator of Rockies Express.

We believe our analysis forms a reasonable estimate of the fair value of Rockies Express. This estimate includes the material input described above, which was generally observable during the period most relevant to our analysis. Regarding the unobservable inputs, significant uncertainties exist with regard to REX's ability to secure attractive revenues beyond 2019. Accordingly, our analysis suggests that the fair value of our investment in Rockies Express could be materially different from the value we have estimated at this time. For example, if REX is able to sustain the level of revenues currently generated beyond 2019, the value of our investment in Rockies Express would be materially enhanced and the indicated value of our investment in Rockies Express could be significantly higher. Conversely, if REX is unable to sell its transport capacity at sufficient rates or in sufficient volumes beyond 2019, the fair value of our investment in Rockies Express could be materially lower than our carrying amount. Separately, future events involving REX equity could occur and may also provide additional information regarding the fair value of our investment in REX.

Sempra Natural Gas developed the models and scenarios used to measure the fair value of our investment in REX. This modeling used inputs from external sources as described above and in the table below, as well as internally available data, such as operating and maintenance budgets used for financial planning purposes. External experts that forecast the future price of natural gas at various physical locations were also engaged to help validate certain scenarios and modeling assumptions. The fair value measurements were reviewed in detail by Sempra Natural Gas' financial management, as well as Sempra Energy's financial management team.

RBS Sempra Commodities

In both the three months and nine months ended September 30, 2011, we reduced our investment in RBS Sempra Commodities to reflect the latest estimates of our expected future cash distributions from the partnership. This fair value measurement was significantly impacted by unobservable inputs (i.e. Level 3 inputs) as described in the table below.

The following table summarizes significant inputs impacting non-recurring fair value measures related to our investments in REX and RBS Sempra Commodities:

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		Estimated		Fair
		Fair		Value	% of Fair Value		Range of
		Value	Valuation Technique	Hierarchy	Measurement	Inputs Used to Develop Measurement	Inputs
Investment in
Rockies Express		$ 369	Market approach	Level 2	67%	Equity sale offer price	100%
			Probability weighted	Level 3	33%	Combined transportation rate assumption(1)	6% - 78%
			discounted cash flow			Counterparty credit risk on existing contracts	Low
						Operation and maintenance escalation rate	0% - 1%
						Forecasted interest rate on debt to be refinanced	5% - 10%
						Discount rate	8% - 10%
Investment in
RBS Sempra
Commodities		$ 126	Discounted cash flow	Level 3	100%	Future cash distributions	90% - 110%
(1)	Transportation rate beyond existing contract terms as a percentage of current mean REX rates.

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COMMITMENTS AND CONTINGENCIES

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Commitments and Contingencies

NOTE 10. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

We accrue losses for legal proceedings 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 coverages and could materially adversely affect our business, cash flows, results of operations, and financial condition. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.

At September 30, 2012, Sempra Energy's accrued liabilities for material legal proceedings, on a consolidated basis, were $427 million. At September 30, 2012, accrued liabilities for material legal proceedings for SDG&E and SoCalGas were $411 million and $5 million, respectively. At September 30, 2012, liabilities of $411 million at Sempra Energy and SDG&E were related to wildfire litigation discussed below.

SDG&E

2007 Wildfire Litigation

In October 2007, San Diego County experienced several catastrophic wildfires. Reports issued by the California Department of Forestry and Fire Protection (Cal Fire) concluded that two of these fires (the Witch and Rice fires) were SDG&E “power line caused” and that a third fire (the Guejito fire) occurred when a wire securing a Cox Communications' (Cox) fiber optic cable came into contact with an SDG&E power line “causing an arc and starting the fire.” Cal Fire reported that the Rice fire burned approximately 9,500 acres and damaged 206 homes and two commercial properties, and the Witch and Guejito fires merged and eventually burned approximately 198,000 acres, resulting in two fatalities, approximately 40 firefighters injured and an estimated 1,141 homes destroyed.

A September 2008 staff report issued by the CPUC's CPSD 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 have 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. These include owners and insurers of properties that were destroyed or damaged in the fires and government entities seeking recovery of firefighting, emergency response, and environmental costs. They assert 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.

In October 2010, the Court of Appeal affirmed the trial court's ruling that these claims must be pursued in individual lawsuits, rather than as class actions on behalf of all persons who incurred wildfire damages. In February 2011, the California Supreme Court denied a petition for review of the affirmance. No trial date is currently scheduled.

SDG&E filed cross-complaints against Cox seeking indemnification for any liability that SDG&E might incur in connection with the Guejito fire, two SDG&E contractors seeking indemnification in connection with the Witch fire, and one SDG&E contractor seeking indemnification in connection with the Rice fire. SDG&E has entered into settlement agreements with Cox and the three contractors for a total of approximately $824 million. Among other things, the settlement agreements provide that SDG&E will defend and indemnify Cox and the three contractors against all compensatory damage claims and related costs arising out of the wildfires.

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 has paid or will 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.

The wildfire litigation also includes claims of 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 settled the claims of approximately 4,700 of these plaintiffs, including all of the government entities. Approximately 1,550 of the approximately 1,750 remaining individual and business plaintiffs have submitted settlement demands and damage estimates totaling approximately $1.4billion. SDG&E does not expect significant additional plaintiffs to file lawsuits given the applicable statutes of limitation, but does expect to receive additional settlement demands and damage estimates from existing plaintiffs as settlement negotiations continue. SDG&E has established reserves for the wildfire litigation as we discuss below.

SDG&E's settled claims and defense costs have exceeded its $1.1 billion of liability insurance coverage and the approximately $824 million received or receivable from third parties to date. It expects that its wildfire reserves and amounts paid to resolve wildfire claims will continue to increase as it obtains additional information.

As we discuss in Note 9, upon consideration of the relevant regulatory and statutory standards and the issues discussed at anex parte meeting with the CPUC Assigned Commissioner, SDG&E has concluded that it is probable that it will be permitted to recover from its utility customers substantially all reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and the amounts recovered from other responsible parties. Accordingly, although such recovery will require future regulatory actions, at September 30, 2012, Sempra Energy and SDG&E have recorded assets of $326 million in Regulatory Assets Arising From Wildfire Litigation Costs on their Condensed Consolidated Balance Sheets, including $292 million related to CPUC operations, which represents the amount substantially equal to the aggregate amount it has paid or reserved for payment for the resolution of wildfire claims and related costs in excess of its liability insurance coverage and amounts received or receivable from third parties. SDG&E will increase the regulatory assets as additional amounts are paid or reserves are recorded.

SDG&E will continue to assess the recovery of these excess wildfire costs from ratepayers. Should SDG&E conclude that the amount of recovery from ratepayers is no longer reasonably estimable or that recovery 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 such recovery was no longer probable or reasonably estimable as of September 30, 2012, the resulting after-tax charge against earnings would have been approximately $175 million. In addition, in periods following any such conclusion, SDG&E's earnings will be adversely impacted by increases in the estimated cost to settle pending wildfire claims. We provide additional information about excess wildfire claims cost recovery in Note 9.

SDG&E's cash flow may be materially adversely affected due to the timing differences between the resolution of claims and the recoveries from utility customers, which may extend over a number of years. Also, recovery from customers will require future regulatory actions, and a failure to obtain substantial or full recovery, 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 position, cash flows and results of operations.

SDG&E will continue to gather information to evaluate and assess the remaining wildfire claims and the likelihood, amount and timing of related recoveries from utility customers and will make appropriate adjustments to wildfire reserves and the related regulatory assets as additional information becomes available.

Since2010, as liabilities for wildfire litigation have become reasonably estimable in the form of settlement demands, damage estimates, and other damage information, SDG&E has recorded related reserves as a liability. The impact of this liability at September 30, 2012 is offset by the recognition of regulatory assets, as discussed above, for reserves in excess of the insurance coverage and recoveries from third parties. Due primarily to the recovery from two of SDG&E's contractors, the impact of the reserves on SDG&E's and Sempra Energy's after-tax earnings was an increase of $1 million and a decrease of $5 million for the three months ended September 30, 2012 and 2011, respectively, and a decrease of $4 million and $7 million for the nine months ended September 30, 2012 and 2011, respectively. At September 30, 2012, wildfire litigation reserves were $411 million ($284 million in current and $127 million in long-term).Additionally, throughSeptember 30, 2012, SDG&E has expended $187 million (excluding amounts covered by insurance and amounts recovered from other responsible third parties) to pay costs associated with the settlement of wildfire claims.

Sunrise Powerlink Electric Transmission Line

SDG&E commenced construction on the Sunrise Powerlink in the fall of 2010. The Sunrise Powerlink is a new 117-mile, 500-kilovolt (kV) electric transmission line between the Imperial Valley and the San Diego region, along a route that generally runs south of the Anza-Borrego Desert State Park. Construction of the transmission line has been completed andthe line was energized and placed inservice in June2012.

The Sunrise Powerlink project was originally approved by the CPUC in December 2008, including approval of the environmental impact review conducted jointly with the BLM. The CPUC subsequently denied or dismissed all requests for rehearing of its approval of the project. In February 2011, the California Supreme Court denied a petition filed jointly by the Utility Consumers' Action Network (UCAN) and the Center for Biological Diversity/Sierra Club challenging the CPUC's decision with regard to implementation of the California Environmental Quality Act (CEQA).

In January 2009, the BLM issued its decision approving the portions of the project, route and environmental review within its jurisdiction. The Interior Board of Land Appeals subsequently denied or dismissed all administrative appeals that were filed challenging the BLM's approval of the project.

In February 2010, parties opposed to the project filed a lawsuit in Federal District Court in San Diego alleging that the BLM failed to properly address the environmental impacts of the approved Sunrise Powerlink route and the related potential development of renewable resources in east San Diego County and Imperial County. In July 2012, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court's grant of the defendants' motion for summary judgment.

In July 2010, the United States Forest Service (USFS) issued its decision approving the portions of the project, route and environmental review within its jurisdiction. The USFS subsequently denied all administrative appeals challenging its approval of the project.

The CPUC and BLM jointly approved the final Project Modification Report for Sunrise Powerlink in September 2010, accepting all of the proposed modifications to the approved route and finding that no additional environmental review was required. In March 2011, opponents of the Sunrise Powerlink filed a petition with the California Supreme Court challenging the CPUC's acceptance of the Project Modification Report. The California Supreme Court denied the petition in April 2011.

In January 2011, project opponents filed a lawsuit in Federal District Court in San Diego alleging that the federal approvals for construction of the project on USFS land and BLM land violated the National Environmental Policy Act and other federal environmental laws. In June 2012, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court's denial of plaintiffs' motion for a preliminary injunction.

In February 2011, opponents of the Sunrise Powerlink 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 CEQA. The Superior Court denied the plaintiffs' petition in July 2012, and the plaintiffs have appealed.

September 2011 Power Outage

In September 2011, a power outage lasting approximately 12 hours affected millions of people from Mexico to southern Orange County, California. Within several days of the outage, several SDG&E customers filed a class action lawsuit in Federal District Court in San Diegoagainst Arizona Public Service Company, Pinnacle West, and SDG&E alleging that the companies failed to prevent the outage. The lawsuit seeks recovery of unspecified amounts of damages, including punitive damages. In July 2012, the court granted SDG&E's motion to dismiss the punitive damages request and dismissed Arizona Public Service Company and Pinnacle West from the lawsuit. In addition, more than 7,000 customers' claims, primarily related to food spoilage, have been submitted directly to SDG&E.The Federal Energy Regulatory Commission (FERC) and North American Electric Reliability Corp. (NERC) conducted a joint inquiryto determine the cause of the power failure and issued a report in May 2012 regarding their findings. The report does not include any findings of failure on SDG&E's part that led to the power failure.

Smart Meters Patent Infringement Lawsuit

In October 2011, SDG&E was sued by a Texas design and manufacturing company in Federal District Court 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.

SoCalGas

SoCalGas, along with Monsanto Co., Solutia, Inc., Pharmacia Corp., and Pfizer, Inc., are defendants in fiveLos Angeles County Superior Court lawsuits filed beginning in April 2011seeking 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 two of the five lawsuits for an amount that is not significant and has been recorded.

Sempra Natural Gas

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 alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and seeks damages of $56.7 million. Liberty filed a counterclaim alleging breach of contract in the inducement and seeks damages of more than $215 million.

Sempra Mexico

Sempra Mexico has been engaged in a long-running land dispute relating to property adjacent to its Energía Costa Azul liquefied natural gas (LNG) terminal near Ensenada, Mexico. The adjacent property is not required by environmental or other regulatory permits 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. In February 2011, based on a complaint by the claimant, the new Ensenada Mayor attempted 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. 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 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.

Additionally, several administrative challenges are pending in Mexico before the Mexican environmental protection agency (SEMARNAT) and/or 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. Also, there are two real property cases pending 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. Sempra Mexico expects further proceedings on each of these matters.

In July 2012, a Mexicali state court issued a ruling declaring the purchase contract by which Termoeléctrica de Mexicali (TDM) acquired the property on which the facility is located to be invalid, on the grounds that the proceeding in which the seller acquired title was invalid. TDM has appealed the ruling, and it is not enforceable while the appeal is pending. In accordance with Mexican law, TDM remains in possession of the property, and its operations have not been affected.

Other Litigation

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 December 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 resolves all issues with regard to sales between the California Department of Water Resources (DWR) 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.

Sempra Energy and several subsidiaries, along with three oil and natural gas companies, the City of Beverly Hills, and the Beverly Hills Unified School District, were defendants in toxic tort lawsuits filed beginning in 2003 in Los Angeles County Superior Court by approximately 1,000 plaintiffs. These lawsuits claimed that various emissions resulted in cancer or fear of cancer. In November 2006, the court granted the defendants' summary judgment motions based on lack of medical causation for the 12 initial plaintiffs scheduled to go to trial first. The court also granted summary judgment excluding punitive damages. In June 2010, a tentative settlement as to Sempra Energy and its subsidiaries was reached for an amount that was not significant and was recorded. The settlement was finalized in August 2012.

As described in Note 4, we hold a noncontrolling interest in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. In March 2012, RBS received a letter from the United Kingdom's Revenue and Customs Department (HMRC) regarding a value-added-tax (VAT) matter related to RBS Sempra Energy Europe (RBS SEE), a former indirect subsidiary of RBS Sempra Commodities that was sold to JP Morgan.The letter states that HMRC is conducting a number of investigations into VAT tax refund claims made by various businesses related to the purchase and sale of carbon credit allowances. The letter also states that HMRC believes it has grounds to deny RBS the ability to reduce its VAT liability by VAT paid during 2009 because it 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 an assessment of £86 million for the VAT paid in connection with these transactions and identified several options for responding, including requesting a review by HMRC and appealing to an independent tribunal.HMRC indicated that the assessment was issued on a protective basis as discussion about the issues is continuing.

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

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 $12.2 billion of secondary financial protection (SFP). If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $375 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. SDG&E's contribution would be up to $47 million. This amount is subject to an annual maximum of $7 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. In addition, the SONGS owners have up to $490 million insurance coverage for outage expenses and replacement power costs due to accidental property damage. This coverage is limited to $3.5 million per week for the first 52 weeks, then $2.8 million per week for up to 110 additional weeks. There is a 12-week waiting period deductible. These insurance coverages are provided through a mutual insurance company. Insured members are subject to retrospective premium assessments. SDG&E could be assessed up to $9.7 million.

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.

We provide additional information about SONGS in Note 9.

CONTRACTUAL COMMITMENTS

We discuss below significant changes in the first ninemonths of 2012 to contractual commitments discussed in Note 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

Natural Gas Contracts

SoCalGas' natural gas purchase and pipeline capacity commitments have increased by $232 million since December 31, 2011. The increase,primarily due to new natural gas purchase and pipeline capacity contracts of $591 million, is offset by a reduction of $359 million from fulfillment of commitmentsin the first nine months of 2012. Net future payments are expected to decrease by $231 million in 2012and increase by $307 million in 2013,$67million in 2014, $34 million in 2015, $4 million in 2016 and $51 million thereaftercompared to December 31, 2011.

Sempra Mexico's natural gas purchase commitments have decreased by $128 million since December 31, 2011, primarily due to changes in forward prices and fulfillment of commitments in the first nine months of 2012. Net future payments are therefore expected to decrease by $81 million in 2012, $22 million in 2013 and $25 million in 2014 compared to December 31, 2011.

Sempra Natural Gas' natural gas purchase and storage capacity commitments haveincreased by $73 million since December 31, 2011, primarily due to new storage capacity contracts in the firstnine months of 2012. Net future payments are expected to decrease by$7 million in 2012, and increase by $14 million in 2013, $10 million in 2014, $11 million in 2015, $11 million in 2016 and $34 million thereafter compared to December 31, 2011.

LNG Purchase Agreements

At September 30, 2012, Sempra Natural Gas has various purchase agreements with major international companies for the supply of LNG to theEnergía Costa Azul and Cameron receipt terminals. We discuss these agreements further in Note 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report. Sempra Natural Gas' commitments under all LNG purchase agreements, reflecting changes in forward prices since December 31, 2011 and actual transactions for the first nine months of 2012, are expected to decrease by $384 million in 2012, $9 million in 2013, $18 million in 2014, $27 million in 2015, $33 million in 2016 and $523million thereafter compared to December 31, 2011.

The LNG commitment amounts above are based on Sempra Natural Gas' commitment to accept the maximum possible delivery of cargoes under the agreements. Actual LNG purchases for the nine months ended September 30, 2012 have been significantly lower than the maximum amounts possible.

Purchased-Power Contracts

SDG&E's commitments under purchased-power contract commitments haveincreased by $1.6 billion since December 31, 2011. Theincrease is primarily due to newcontracts associated with renewable energy development projects and changes in expected prices. Net future payments are therefore expected to decrease by $47 million in 2012,and increase by $18 million in 2013, $61 million in 2014,$66 million in 2015, $67 million in 2016and $1.4billion thereafter compared to December 31, 2011.

Sempra South American Utilities' purchased-power contracts have increased by $96million since December 31, 2011, primarily due to foreign currency translation (as the contracts are denominated in the local currency),offset by changes in expected prices and fulfillment of commitments in the first nine months of 2012. Net future payments for the purchased-power contracts at Luz del Sur are expected to decrease by $291 million in 2012, increase by $15 million in 2013 and $2 million in 2014, decrease by $1 million in 2015, and to increase by $8 million in 2016 and $105million thereafter. Net future payments for the purchased-power contracts at Chilquinta Energíaare expected to decrease by $205 million in 2012, and increase by $28 million in 2013, $32 million in 2014, $34 million in 2015, $34 million in 2016 and $335million thereafter. These amounts are based on estimated future purchases at current contracted rates, as the contracts require no minimum purchases.

Operating Leases

Sempra Renewables entered into a land lease for the Copper Mountain Solar 2 project,which lease expires in 2054. Future payments on the lease are $2 million in 2013, $2 million in 2014, $2 million in 2015, $2 million in 2016 and $57 million thereafter.

Construction and Development Projects

In the first nine months of 2012, significant increases to contractual commitments at SDG&E were $34 million for electric transmission and distribution systems, $11 million for infrastructure improvements for natural gas transmission and distribution operations and $196 million for construction costs associated with the ECO Substation.The future payments for these contractual commitments are expected to be $62 million in 2012, $159 million in 2013 and $20 million in 2014.

In connection with the completion of the Sunrise Powerlink project,the CPUC required that SDG&E establish a fire mitigation fund to minimize the risk of fire as well as reduce the potential wildfire impact on residences and structures near the Sunrise Powerlink. The future payments for these contractual commitments are expected to be approximately $3 million per year, subject to escalation of 2 percent per year, for 58 years.At September 30, 2012, the present value of these future payments of $116 million has been recorded asa regulatory asset as the amounts represent a cost that will be recovered from customers in the future, and the related liability was $113 million.

In the first nine months of 2012, significant increases to contractual commitments at SoCalGas were $60 million for construction and infrastructure improvements for natural gas transmission and distribution operations. The payments for these contractual commitments are all expected to be in 2012.

Other

In July 2012, SDG&E received $85 million from Citizens Sunrise Transmission, LLC (Citizens), a subsidiary of Citizens Energy Corporation. For this payment, under the terms of the agreement with Citizens, SDG&E will provide Citizens with access to a segment of the Sunrise Powerlink transmission line known as the Border-East transmission line equal to 50 percent of the transfer capacity of this portion of the line for a period of 30 years. After the 30-year contract term, the transfer capability will revert to SDG&E. SDG&E will amortize deferred revenues from the use of the transfer capability over the 30-year term, and depreciation for 50 percent of the Border-East transmission line segment will be accelerated from an estimated 58-year life to 30 years.

XML

OTHER FINANCIAL DATA - PREFERRED STOCK (Details) (USD $)	Jun. 30, 2011
Preferred Stock (Details) [Abstract]
Preferred stock redeemed	$ 81,000,000
Preferred stock redemption price per share, minimum	100
Preferred stock redemption price per share, maximum	101.50
Accrued preferred stock dividends at redemption date	$ 1,000,000

XML

FAIR VALUE MEASUREMENTS 2 (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net [Line Items]
Fair value of cash collateral receivables not offset against derivatives	$ 46	$ 20
San Diego Gas and Electric Company and Subsidiary [Member]
Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net [Line Items]
Fair value of cash collateral receivables not offset against derivatives	20	10
Southern California Gas Company [Member]
Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net [Line Items]
Fair value of cash collateral receivables not offset against derivatives	$ 4	$ 2

XML

OTHER FINANCIAL DATA (Tables)

3 Months Ended

Sep. 30, 2012

Other Financial Data (Tables) [Abstract]

Goodwill Table

GOODWILL
(Dollars in millions)
			Sempra
			South American		Sempra		Sempra
			Utilities		Mexico		Natural Gas		Total
Balance as of December 31, 2011		$	949	$	25	$	62	$	1,036
Foreign currency translation(1)			63		―		―		63
Acquisition of subsidiary			―		―		10		10
Balance at September 30, 2012		$	1,012	$	25	$	72	$	1,109
(1)	We record the offset of this fluctuation to other comprehensive income.

Net Periodic Benefit Cost Table

NET PERIODIC BENEFIT COST – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended September 30,				Three months ended September 30,
	2012		2011		2012		2011
Service cost	$	23	$	20	$	4	$	8
Interest cost		40		41		11		16
Expected return on assets		(38)		(36)		(13)		(12)
Amortization of:
Prior service cost		―		1		―		―
Actuarial loss		12		8		2		4
Settlement		1		1		―		―
Regulatory adjustment		9		31		3		2
Total net periodic benefit cost	$	47	$	66	$	7	$	18
	Nine months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Service cost	$	68	$	63	$	19	$	23
Interest cost		122		126		39		49
Expected return on assets		(116)		(109)		(40)		(36)
Amortization of:
Prior service cost (credit)		2		3		(2)		―
Actuarial loss		35		26		9		13
Settlement		8		11		―		―
Regulatory adjustment		(9)		6		8		6
Total net periodic benefit cost	$	110	$	126	$	33	$	55

NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended September 30,				Three months ended September 30,
	2012		2011		2012		2011
Service cost	$	7	$	6	$	1	$	1
Interest cost		11		12		2		2
Expected return on assets		(11)		(10)		(1)		(1)
Amortization of:
Prior service cost		―		―		1		1
Actuarial loss		4		2		―		―
Settlement		(1)		―		―		―
Regulatory adjustment		7		15		1		1
Total net periodic benefit cost	$	17	$	25	$	4	$	4
	Nine months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Service cost	$	21	$	21	$	5	$	5
Interest cost		34		37		6		7
Expected return on assets		(35)		(35)		(5)		(5)
Amortization of:
Prior service cost		1		1		3		3
Actuarial loss		11		7		―		―
Settlement		1		1		―		―
Regulatory adjustment		7		13		2		2
Total net periodic benefit cost	$	40	$	45	$	11	$	12

NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	Three months ended September 30,				Three months ended September 30,
	2012		2011		2012		2011
Service cost	$	13	$	10	$	2	$	7
Interest cost		24		24		9		12
Expected return on assets		(23)		(21)		(10)		(10)
Amortization of:
Prior service cost (credit)		―		1		(1)		(1)
Actuarial loss		6		4		1		4
Regulatory adjustment		2		16		2		1
Total net periodic benefit cost	$	22	$	34	$	3	$	13
	Nine months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Service cost	$	40	$	34	$	12	$	17
Interest cost		74		74		31		39
Expected return on assets		(72)		(64)		(33)		(30)
Amortization of:
Prior service cost (credit)		1		2		(5)		(3)
Actuarial loss		17		12		8		13
Settlement		1		1		―		―
Regulatory adjustment		(16)		(7)		6		4
Total net periodic benefit cost	$	45	$	52	$	19	$	40

Contributions to Benefit Plans Table

	Sempra Energy
(Dollars in millions)	Consolidated		SDG&E		SoCalGas
Contributions through September 30, 2012:
Pension plans	$	111	$	36	$	45
Other postretirement benefit plans		32		10		19
Total expected contributions in 2012:
Pension plans	$	123	$	45	$	47
Other postretirement benefit plans		41		13		23

Earnings Per Share Computations Table

EARNINGS PER SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
		Three months ended September 30,				Nine months ended September 30,
		2012		2011(1)		2012		2011(1)
Numerator:
Earnings/Income attributable to common shareholders		$	268	$	289	$	566	$	1,046
Denominator:
Weighted-average common shares
outstanding for basic EPS			241,689		239,545		241,133		239,693
Dilutive effect of stock options, restricted
stock awards and restricted stock units			4,113		2,335		3,880		2,262
Weighted-average common shares
outstanding for diluted EPS			245,802		241,880		245,013		241,955
Earnings per share:
Basic		$	1.11	$	1.21	$	2.35	$	4.36
Diluted		$	1.09	$	1.20	$	2.31	$	4.32
(1)	As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

Total Shareholder Return Ranking Table

Four-Year Cumulative Total Shareholder Return Ranking versus S&P 500 Utilities Index(1)	Number of Sempra Energy Common Shares Received for Each Restricted Stock Unit(2)
75th Percentile or Above	1.5
50th Percentile	1
35th Percentile or Below	―
(1) If Sempra Energy ranks at or above the 50th percentile compared to the S&P 500 Index, participants will receive a minimum of 1.0 share for each restricted stock unit.
(2) Participants may also receive additional shares for dividend equivalents on units subject to restricted stock units, which are reinvested to purchase additional units that become subject to the same vesting conditions as the restricted stock units to which the dividends relate.

Capitalized Financing Costs Table

CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Sempra Energy Consolidated:
AFUDC related to debt	$	5	$	10	$	32	$	27
AFUDC related to equity		13		26		80		67
Other capitalized financing costs		13		6		40		20
Total Sempra Energy Consolidated	$	31	$	42	$	152	$	114
SDG&E:
AFUDC related to debt	$	3	$	8	$	26	$	22
AFUDC related to equity		6		21		61		54
Total SDG&E	$	9	$	29	$	87	$	76
SoCalGas:
AFUDC related to debt	$	2	$	2	$	6	$	5
AFUDC related to equity		7		5		19		13
Total SoCalGas	$	9	$	7	$	25	$	18

Income Tax Expense (Benefit) Associated with Other Comprehensive Income Table

INCOME TAX EXPENSE (BENEFIT) ASSOCIATED WITH OTHER COMPREHENSIVE INCOME
(Dollars in millions)
		Three months ended September 30,
		2012						2011
		Share-		Non-				Share-		Non-
		holders'		controlling		Total		holders'		controlling		Total
		Equity(1)		Interests		Equity		Equity(1)		Interests		Equity
Sempra Energy Consolidated:
Foreign currency translation adjustments		$	―	$	―	$	―	$	(1)	$	―	$	(1)
Net actuarial (loss) gain			(7)		―		(7)		1		―		1
Financial instruments			(1)		―		(1)		(11)		―		(11)
SoCalGas:
Financial instruments		$	1	$	―	$	1	$	―	$	―	$	―
		Nine months ended September 30,
		2012						2011
		Share-		Non-				Share-		Non-
		holders'		controlling		Total		holders'		controlling		Total
		Equity(1)		Interests		Equity		Equity(1)		Interests		Equity
Sempra Energy Consolidated:
Foreign currency translation adjustments		$	―	$	―	$	―	$	(1)	$	―	$	(1)
Net actuarial (loss) gain			(4)		―		(4)		5		―		5
Financial instruments			(5)		―		(5)		(11)		―		(11)
SoCalGas:
Financial instruments		$	1	$	―	$	1	$	1	$	―	$	1
(1)	Shareholders’ equity of Sempra Energy Consolidated or SoCalGas as indicated in left margin.

Shareholders' Equity and Noncontrolling Interests Table

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS
(Dollars in millions)
		Sempra
		Energy		Non-
		Shareholders’		controlling		Total
		Equity		Interests		Equity
Balance at December 31, 2011	$	9,775	$	403	$	10,178
Comprehensive income		671		42		713
Preferred dividends of subsidiaries		(5)		―		(5)
Share-based compensation expense		33		―		33
Common stock dividends declared		(435)		―		(435)
Issuance of common stock		50		―		50
Repurchase of common stock		(16)		―		(16)
Common stock released from ESOP		9		―		9
Equity contributed by noncontrolling interest		―		5		5
Distributions to noncontrolling interests		―		(36)		(36)
Balance at September 30, 2012	$	10,082	$	414	$	10,496
Balance at December 31, 2010	$	8,990	$	211	$	9,201
Comprehensive income (loss)		879		(14)		865
Preferred dividends of subsidiaries		(6)		―		(6)
Share-based compensation expense		36		―		36
Common stock dividends declared		(346)		―		(346)
Issuance of common stock		22		―		22
Tax benefit related to share-based compensation		6		―		6
Repurchase of common stock		(18)		―		(18)
Common stock released from ESOP		15		―		15
Distributions to noncontrolling interests		―		(9)		(9)
Equity contributed by noncontrolling interest		―		6		6
Acquisition of South American entities		―		279		279
Purchase of noncontrolling interests in subsidiary		(4)		(39)		(43)
Redemption of preferred stock of subsidiary		―		(80)		(80)
Balance at September 30, 2011	$	9,574	$	354	$	9,928

SHAREHOLDER’S EQUITY AND NONCONTROLLING INTEREST
(Dollars in millions)
		SDG&E		Non-
		Shareholder’s		controlling		Total
		Equity		Interest		Equity
Balance at December 31, 2011	$	3,739	$	102	$	3,841
Comprehensive income		378		10		388
Preferred stock dividends declared		(4)		―		(4)
Distributions to noncontrolling interest		―		(22)		(22)
Balance at September 30, 2012	$	4,113	$	90	$	4,203
Balance at December 31, 2010	$	3,108	$	113	$	3,221
Comprehensive income (loss)		278		(28)		250
Preferred stock dividends declared		(4)		―		(4)
Capital contribution		200		―		200
Equity contributed by noncontrolling interest		―		6		6
Balance at September 30, 2011	$	3,582	$	91	$	3,673

Amounts Due To and From Affiliates at SDG&E and SoCalGas Table

AMOUNTS DUE TO AND FROM AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
		September 30,		December 31,
		2012		2011
SDG&E
Current:
Due from SoCalGas		$	16	$	2
Due from various affiliates			1		65
		$	17	$	67
Due to Sempra Energy		$	20	$	14
Income taxes due from Sempra Energy(1)		$	149	$	97
SoCalGas
Current:
Due from Sempra Energy		$	280	$	23
Due from various affiliates			―		17
		$	280	$	40
Due to SDG&E		$	16	$	2
Income taxes due from Sempra Energy(1)		$	15	$	17
(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 the companies’ having always filed a separate return.

Revenues From Unconsolidated Affiliates at SDG&E and SoCalGas Table

REVENUES FROM UNCONSOLIDATED AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
SDG&E	$	2	$	3	$	6	$	6
SoCalGas		17		13		48		38

Amounts Recorded For Transactions with RBS Sempra Commodities Table

AMOUNTS RECORDED FOR TRANSACTIONS WITH RBS SEMPRA COMMODITIES
(Dollars in millions)
		Three months ended September 30, 2011(1)		Nine months ended September 30, 2011(1)
Revenues:
Sempra Mexico		$	―	$	37
Sempra Natural Gas			―		7
Cost of natural gas:
Sempra Mexico		$	3	$	74
Sempra Natural Gas			―		3
(1)	With the exception of Sempra Mexico, whose contract with RBS Sempra Commodities expired in July 2011, amounts only include activities prior to May 1, 2011, the date by which substantially all the contracts with RBS Sempra Commodities were assigned to buyers of the joint venture businesses.

Other Income and Expense Table

OTHER INCOME, NET
(Dollars in millions)
		Three months ended September 30,				Nine months ended September 30,
		2012		2011		2012		2011
Sempra Energy Consolidated:
Allowance for equity funds used during construction		$	13	$	26	$	80	$	67
Investment gains (losses)(1)			17		(6)		27		13
Gains (losses) on interest rate and foreign exchange instruments, net			1		(26)		11		(14)
Regulatory interest, net(2)			―		―		1		1
Sundry, net			13		18		18		19
Total		$	44	$	12	$	137	$	86
SDG&E:
Allowance for equity funds used during construction		$	6	$	21	$	61	$	54
Regulatory interest, net(2)			―		―		1		1
Sundry, net			(1)		5		(3)		―
Total		$	5	$	26	$	59	$	55
SoCalGas:
Allowance for equity funds used during construction		$	7	$	5	$	19	$	13
Sundry, net			(1)		(2)		(5)		(4)
Total		$	6	$	3	$	14	$	9
(1)	Represents investment gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
(2)	Interest on regulatory balancing accounts.

Income Tax Expense and Effective Income Tax Rates Table

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
		Three months ended September 30,
	2012					2011
			Effective				Effective
		Income Tax	Income			Income Tax	Income
		Expense	Tax Rate			Expense	Tax Rate
Sempra Energy Consolidated	$	49	15	%	$	75	19	%
SDG&E		38	17			63	32
SoCalGas		37	34			41	34
		Nine months ended September 30,
	2012					2011
			Effective				Effective
		Income Tax	Income			Income Tax	Income
		Expense	Tax Rate			Expense	Tax Rate
Sempra Energy Consolidated	$	48	8	%	$	289	22	%
SDG&E		151	27			154	35
SoCalGas		105	35			106	34

Variable Interest Entity Table

AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Operating revenues
Electric	$	―	$	―	$	―	$	―
Natural gas		―		―		―		―
Total operating revenues		―		―		―		―
Operating expenses
Cost of electric fuel and purchased power		(26)		(29)		(66)		(55)
Operation and maintenance		4		1		15		23
Depreciation and amortization		7		7		19		20
Total operating expenses		(15)		(21)		(32)		(12)
Operating income		15		21		32		12
Other income (expense), net		―		4		(1)		―
Interest expense		(3)		(4)		(8)		(6)
Income before income taxes/Net income		12		21		23		6
Earnings attributable to noncontrolling interest		(12)		(21)		(23)		(6)
Earnings	$	―	$	―	$	―	$	―

Ownership Interests Held By Others Table

OTHER NONCONTROLLING INTERESTS
(Dollars in millions)
		Percent Ownership Held by Others			September 30, 2012		December 31, 2011
Bay Gas Storage, Ltd.(1)		9	%	$	19	$	17
Southern Gas Transmission Company(1)		49			1		1
Liberty Gas Storage, LLC(1)		25			13		9
Tecsur		10			4		4
Luz del Sur		20			230		216
Chilquinta Energía subsidiaries		15 - 43			37		34
Otay Mesa VIE (at SDG&E)		100			90		102
Total Sempra Energy				$	394	$	383
(1)	Part of Sempra Natural Gas.

Schedule of Inventory

INVENTORY BALANCES
(Dollars in millions)
	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
	Natural Gas				Materials and supplies				Total
SDG&E	$	2	$	6	$	81	$	76	$	83	$	82
SoCalGas		142		128		24		23		166		151
Sempra South American Utilities		―		―		37		36		37		36
Sempra Mexico		10		10		8		7		18		17
Sempra Natural Gas		85		51		9		9		94		60
Sempra Energy Consolidated	$	239	$	195	$	159	$	151	$	398	$	346

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RECENT INVESTMENT ACTIVITY 2 (DETAILS) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2011		Sep. 30, 2011		Sep. 30, 2012 Willmut Gas [Member]	Sep. 30, 2012 Willmut Gas [Member]	May 20, 2012 Willmut Gas [Member]	Sep. 30, 2012 South America Acquisition [Member]	Sep. 30, 2011 South America Acquisition [Member]	Sep. 30, 2012 South America Acquisition [Member]	Sep. 30, 2011 South America Acquisition [Member]	Sep. 13, 2011 Luz Del Sur [Member]	Apr. 06, 2011 Luz Del Sur [Member]	Apr. 06, 2011 Chilquinta Energia [Member]
Property, plant and equipment
Property, plant and equipment							$ 17
Total liabilities							(10)
Goodwill							10
Remeasurement of equity method investments			277	[1]
Revenue of acquiree since acquisition date					3	5		356	345	1,100	706
Net Income of acquiree since acquisition date								56	60	155	108
Earnings of acquiree since acquisition date								49	52	135	92
Pro forma revenues	2,576		7,775
Pro forma earnings	$ 289	[1]	$ 794	[1],[2]
Ownership Percentage Before Acquisition													38.00%	50.00%
Acquired percentage interest in joint venture							100.00%							100.00%
Ownership percentage after Luz Del Sur tender offer												80.00%

[1] As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

[2] Excludes the $277 million gain related to remeasurement of equity method investments.

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DERIVATIVE FINANCIAL INSTRUMENTS 6 (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012
Derivative Credit Risk Related Contingent Features [Line Items]
Derivative, Net Liability Position, Aggregate Fair Value	$ 11
Additional Collateral Aggregate Fair Value	11
San Diego Gas and Electric Company and Subsidiary [Member]
Derivative Credit Risk Related Contingent Features [Line Items]
Derivative, Net Liability Position, Aggregate Fair Value	6
Additional Collateral Aggregate Fair Value	$ 6

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OTHER FINANCIAL DATA - INVENTORY (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Inventory [Line Items]
Energy Related Inventory, Natural Gas in Storage	$ 239	$ 195
Energy Related Inventory, Materials And Supplies	159	151
Inventory, Total	398	346	[1],[2]
S D G E Segment [Member]
Inventory [Line Items]
Energy Related Inventory, Natural Gas in Storage	2	6
Energy Related Inventory, Materials And Supplies	81	76
Inventory, Total	83	82
So Cal Gas Segment [Member]
Inventory [Line Items]
Energy Related Inventory, Natural Gas in Storage	142	128
Energy Related Inventory, Materials And Supplies	24	23
Inventory, Total	166	151
Sempra South American Utilities Segment [Member]
Inventory [Line Items]
Energy Related Inventory, Materials And Supplies	37	36
Inventory, Total	37	36
Sempra Mexico Segment [Member]
Inventory [Line Items]
Energy Related Inventory, Natural Gas in Storage	10	10
Energy Related Inventory, Materials And Supplies	8	7
Inventory, Total	18	17
Sempra Natural Gas Segment [Member]
Inventory [Line Items]
Energy Related Inventory, Natural Gas in Storage	85	51
Energy Related Inventory, Materials And Supplies	9	9
Inventory, Total	$ 94	$ 60

[1] As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

[2] Derived from audited financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011		Sep. 30, 2012	Sep. 30, 2011
Comprehensive income, net of income tax
Net income	$ 290	$ 319	[1]	$ 615	$ 1,073	[1]
Foreign currency translation adjustments	88	(139)	[1]	125	(110)	[1]
Reclassification to net income of foreign currency translation adjustments related to equity method investments					(54)	[1],[2]
Financial instruments	(7)	(39)	[1]	(22)	(52)	[1]
Net actuarial gain	(10)	1	[1]	(5)	8	[1]
Total other comprehensive income (loss)	71	(177)	[1]	98	(208)	[1]
Total Comprehensive Income Before Preferred Stock Dividend Requirements	361	142	[1]	713	865	[1]
Preferred dividends of subsidiaries	(2)	(1)	[1]	(5)	(6)	[1]
Comprehensive Income Net Of Tax	359	141	[1]	708	859	[1]
San Diego Gas and Electric Company and Subsidiary [Member]
Comprehensive income, net of income tax
Net income	188	136		401	283
Financial instruments	(4)	(25)		(13)	(34)
Net actuarial gain		1			1
Total other comprehensive income (loss)	(4)	(24)		(13)	(33)
Total Comprehensive Income Before Preferred Stock Dividend Requirements	184	112		388	250
Southern California Gas Company [Member]
Comprehensive income, net of income tax
Net income	71	81		191	209
Financial instruments		1		1	2
Total other comprehensive income (loss)		1		1	2
Total Comprehensive Income Before Preferred Stock Dividend Requirements	71	82		192	211
Total Shareholders' Equity
Comprehensive income, net of income tax
Net income	270	290	[1]	571	1,052	[1]
Foreign currency translation adjustments	80	(132)	[1]	114	(109)	[1]
Reclassification to net income of foreign currency translation adjustments related to equity method investments					(54)	[1],[2]
Financial instruments	(3)	(14)	[1]	(9)	(18)	[1]
Net actuarial gain	(10)	1	[1]	(5)	8	[1]
Total other comprehensive income (loss)	67	(145)	[1]	100	(173)	[1]
Total Comprehensive Income Before Preferred Stock Dividend Requirements	337	145	[1]	671	879	[1]
Preferred dividends of subsidiaries	(2)	(1)	[1]	(5)	(6)	[1]
Comprehensive Income Net Of Tax	335	144	[1]	666	873	[1]
Total Shareholders' Equity | San Diego Gas and Electric Company and Subsidiary [Member]
Comprehensive income, net of income tax
Net income	176	115		378	277
Net actuarial gain		1			1
Total other comprehensive income (loss)		1			1
Total Comprehensive Income Before Preferred Stock Dividend Requirements	176	116		378	278
Noncontrolling Interests
Comprehensive income, net of income tax
Net income	20	29	[1]	44	21	[1]
Foreign currency translation adjustments	8	(7)	[1]	11	(1)	[1]
Financial instruments	(4)	(25)	[1]	(13)	(34)	[1]
Total other comprehensive income (loss)	4	(32)	[1]	(2)	(35)	[1]
Total Comprehensive Income Before Preferred Stock Dividend Requirements	24	(3)	[1]	42	(14)	[1]
Comprehensive Income Net Of Tax	24	(3)	[1]	42	(14)	[1]
Noncontrolling Interests | San Diego Gas and Electric Company and Subsidiary [Member]
Comprehensive income, net of income tax
Net income	12	21		23	6
Financial instruments	(4)	(25)		(13)	(34)
Total other comprehensive income (loss)	(4)	(25)		(13)	(34)
Total Comprehensive Income Before Preferred Stock Dividend Requirements	$ 8	$ (4)		$ 10	$ (28)

[1] As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.

[2] Related to the acquisition of Chilquinta Energía and Luz del Sur.

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INVESTMENTS IN UNCONSOLIDATED ENTITIES

3 Months Ended

Sep. 30, 2012

Notes to Consolidated Financial Statements [Abstract]

Investments in Unconsolidated Entities

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

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

Sempra Renewables

For the nine months ended September 30, 2012, Sempra Renewables invested $296 million in its renewable wind generation joint ventures, of which $249 million was invested in the Flat Ridge 2 Wind Farm project.

Sempra Natural Gas

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), that links producing areas in the Rocky Mountains region to the upper Midwest and the eastern United States.In August 2012, Kinder Morgan Energy Partners L.P. (KMP) announced the sale of its 50 percent interest in Rockies Express, as part of a larger asset group, to Tallgrass Energy Partners, L.P. (Tallgrass).Phillips 66 owns the remaining interest of 25 percent. Our total investment in Rockies Express is accounted for as an equity method investment.

The general partner of KMP is Kinder Morgan, Inc. (KMI). As a condition of KMI receiving antitrust approval from the Federal Trade Commission (FTC) for its acquisition of El Paso Corporation, KMI agreed to divest certain assets in its natural gas pipeline group. Included in these assets is KMP's interest in Rockies Express. KMP recorded remeasurement losses during the firstnine monthsof 2012 associated with these discontinued operations. We have recorded impairments of our partnership investment in Rockies Expressof $300 million ($179 million after-tax) in the quarter ended June 30, 2012 and an additional $100 million ($60 million after-tax) in the quarter ended September 30, 2012. Our remaining carrying value in Rockies Express as of September 30, 2012 is $369 million. We recorded the write-downs as a result of our estimate of fair value for our investmentat the reporting date and our conclusion that the impairmentsare other-than-temporary, as required by GAAP. We discuss the fair value measurement of our investment in Rockies Express in Note 8.

RBS SEMPRA COMMODITIES

RBS Sempra Commodities LLP (RBS Sempra Commodities) is a United Kingdom limited liability partnership that owned and operated commodities-marketing businesses previously owned by us. We and our partner in the joint venture, The Royal Bank of Scotland plc (RBS), sold substantially all of the partnership's businesses and assets in four separate transactions completed in July, November and December of 2010 and February of 2011. We account for our investment in RBS Sempra Commodities under the equity method, and report our share of partnership earnings and other associated costs in Parent and Other.

In April 2011, we and RBS entered into a letter agreement (Letter Agreement) which amended certain provisions of the agreements that formed RBS Sempra Commodities. The Letter Agreement addresses the wind-down of the partnership and the distribution of the partnership's remaining assets. In accordance with the Letter Agreement, we received distributions in the nine months ended September 30, 2011 of $329 million on April 15, 2011 and $98 million on August 9, 2011.The investment balance of $126 million at September 30, 2012 reflects remaining distributions expected to be receivedfrom the partnership in accordance with the Letter Agreement. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 10 under “Other Litigation.”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.

In connection with the Letter Agreement described above, we also released RBS from its indemnification obligations with respect to the items for which J.P. Morgan Chase & Co. (JP Morgan), one of the buyers of the partnership's businesses, has agreed to indemnify us.

We recorded no equity earnings or losses related to the partnership for the three months or nine months ended September 30, 2012. Pretax equity losses from RBS Sempra Commodities were $16 million and $24 million for the three months and nine months ended September 30, 2011, respectively.Included in the equity losses is an impairment charge of $16 million ($10 million after-tax) for the three months and nine months ended September 30, 2011 to reduce our investment in RBS Sempra Commodities. We discuss the fair value measurement of our investment in the partnership in Note 8.

We discuss the RBS Sempra Commodities sales transactions, the Letter Agreement and other matters concerning the partnership in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

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COMMITMENTS AND CONTINGENCIES - NUCLEAR INSURANCE (Details) (San Diego Gas and Electric Company and Subsidiary [Member], USD $)	Sep. 30, 2012
San Diego Gas and Electric Company and Subsidiary [Member]
Schedule Of Nuclear Insurance [Line Items]
Nuclear Liability Insurance Coverage, Maximum	$ 375,000,000
Secondary Financial Protection, Maximum	12,200,000,000
Secondary Financial Protection, Company Contribution, Maximum	47,000,000
Secondary Financial Protection, Company Contribution, Annual Maximum	7,000,000
Nuclear Property Insurance Coverage, Maximum	2,750,000,000
Nuclear Property Damage Insurance Coverage, Maximum	490,000,000
Nuclear Property Damage Insurance Coverage, Weekly Maximum	3,500,000
Nuclear Property Damage Insurance Coverage, Weekly Minimum	2,800,000
Nuclear Property Damage Insurance, Premium Assessment	9,700,000
Nuclear Property Insurance Terrorism Coverage, Maximum	$ 3,240,000,000

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INVESTMENTS IN UNCONSOLIDATED ENTITIES (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended		3 Months Ended			9 Months Ended
	Aug. 09, 2011	Apr. 15, 2011	Sep. 30, 2012	Jun. 30, 2012	Sep. 30, 2011	Sep. 30, 2011
Investment In Joint Venture Disclosure [Abstract]
Distributions from RBS Sempra Commodities LLP	$ 98	$ 329
Investment in RBS Sempra Commodities LLP			126
Pretax equity earnings (losses) from RBS Sempra Commodities LLP					(16)	(24)
Loss on impairment of RBS Sempra Commodities LLP					(16)	(16)
Loss on impairment of RBS Sempra Commodities LLP, after tax					(10)	(10)
Schedule of Equity Method Investments [Line Items]
Sempra Renewables' Equity Method Investments In Joint Ventures			296
Loss on impairment of investment in Rockies Express			100	300
Loss on impairment of investment in Rockies Express, after tax			60	179
Investment in Rockies Express			369
Rockies Express [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage in equity method investee			25.00%
Ownership percentage of minority partner in equity method investee			25.00%
Ownership percentage of operating partner in equity method investee			50.00%
Flat Ridge 2 [Member]
Schedule of Equity Method Investments [Line Items]
Sempra Renewables' Equity Method Investments In Joint Ventures			$ 249

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OTHER FINANCIAL DATA - TRANSACTIONS WITH AFFILIATES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011	Sep. 30, 2012		Sep. 30, 2011	Dec. 31, 2011
Transactions With Affiliates Disclosure [Line Items]
Due from affiliate, current	$ 0			$ 0
Sempra Mexico Segment [Member]
Transactions With Joint Venture [Line Items]
Revenues from transactions with RBS Sempra Commodities			0			37
Cost of natural gas from transactions with RBS Sempra Commodities			3			74
Sempra Natural Gas Segment [Member]
Transactions With Joint Venture [Line Items]
Revenues from transactions with RBS Sempra Commodities			0			7
Cost of natural gas from transactions with RBS Sempra Commodities						3
San Diego Gas and Electric Company and Subsidiary [Member]
Transactions With Affiliates Disclosure [Line Items]
Due from affiliate, current	17			17			67
Due to affiliate, current	20			20			14
Revenues from unconsolidated affiliates	2		3	6		6
Southern California Gas Company [Member]
Transactions With Affiliates Disclosure [Line Items]
Due from affiliate, current	280			280			40
Revenues from unconsolidated affiliates	17		13	48		38
Affiliate Of Investee [Member] | Parent Company Member
Transactions With Affiliates Disclosure [Line Items]
Interest rate on due from affiliate, noncurrent	7.41%
Loan to unconsolidated affiliate, principal	18			18
Loan to unconsolidated affiliate, accrued interest	7			7
Due to/from Sempra Energy | San Diego Gas and Electric Company and Subsidiary [Member]
Transactions With Affiliates Disclosure [Line Items]
Income taxes due from (to) Sempra Energy	149	[1]		149	[1]		97	[1]
Due to/from Sempra Energy | Southern California Gas Company [Member]
Transactions With Affiliates Disclosure [Line Items]
Due from affiliate, current	280			280			23
Income taxes due from (to) Sempra Energy	15	[1]		15	[1]		17	[1]
Subsidiary Of Common Parent S D G E [Member] | Southern California Gas Company [Member]
Transactions With Affiliates Disclosure [Line Items]
Due from affiliate, current	0			0
Due to affiliate, current							2
Subsdiary Of Common Parent So Cal Gas [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Transactions With Affiliates Disclosure [Line Items]
Due from affiliate, current							2
Subsidiary Of Common Parent Other Affiliates [Member] | San Diego Gas and Electric Company and Subsidiary [Member]
Transactions With Affiliates Disclosure [Line Items]
Due from affiliate, current	1			1			65
Subsidiary Of Common Parent Other Affiliates [Member] | Southern California Gas Company [Member]
Transactions With Affiliates Disclosure [Line Items]
Due from affiliate, current							$ 17

[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 the companies’ having always filed a separate return.

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RECENT INVESTMENT ACTIVITY (Tables)

3 Months Ended

Sep. 30, 2012

Recent Investment Activity (Tables) [Abstract]

Schedule of Business Acquisition Proforma Information Table

		Three months ended		Nine months ended
(Dollars in millions)		September 30, 2011		September 30, 2011
Revenues		$	2,576	$	7,775
Earnings(1)			289		794	(2)
(1)	As adjusted for the retrospective effect of change in accounting principle as we discuss in Note 1.
(2)	Excludes the $277 million gain related to remeasurement of equity method investments.